TSX: TUI.UN
CALGARY, March 16 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True,"
"Company" or the "Trust") announces its financial and operating results for
the year ended December 31, 2008.
HIGHLIGHTS
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Years ended December 31,
2008 2007
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FINANCIAL (unaudited)
(CDN$000s except unit and per unit amounts)
Revenue (before royalties and hedging(1)) 265,385 258,490
Funds flow from operations(2) 77,893 101,172
Per basic trust unit $0.99 $1.33
Per diluted trust unit(5) $0.98 $1.33
Net loss (19,590) (24,267)
Per basic trust unit $(0.25) $(0.32)
Per diluted trust unit(5) $(0.25) $(0.32)
Distributions declared 36,334 73,451
Per unit $0.46 $0.96
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Exploration and development 36,699 87,347
Corporate and property acquisitions 6,303 1,505
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Capital expenditures - cash 43,002 88,852
Property dispositions - cash (44,340) (31,808)
Other - non-cash 3,710 (530)
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Total capital expenditures - net 2,372 56,514
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Long-term debt 132,388 168,475
Convertible debentures(3) 81,124 79,407
Working capital deficiency 1,492 2,431
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Total net debt(3) 215,004 250,313
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Total assets 736,117 880,252
Unitholders' equity 406,461 462,780
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OPERATING
Daily sales volumes
Crude oil, condensate and NGLs (bbls/d) 4,333 5,330
Natural gas (mcf/d) 45,202 64,853
Total oil equivalent (boe/d) 11,867 16,139
Average prices
Crude oil, condensate and NGLs ($/bbl) 76.75 48.71
Crude oil, condensate and NGLs
(including hedging(1)) ($/bbl) 64.24 47.74
Natural gas ($/mcf) 8.50 6.73
Natural gas (including hedging(1)) ($/mcf) 8.00 7.08
Total oil equivalent ($/boe) 60.42 43.13
Total oil equivalent
(including hedging(1)) ($/boe) 53.92 44.23
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Years ended December 31,
2008 2007
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Statistics
Operating netback(4) ($/boe) 30.91 22.21
Operating netback(4)
(including hedging(1)) ($/boe) 24.41 23.31
Transportation ($/boe) 1.62 1.35
Production expenses ($/boe) 15.33 11.59
General & administrative ($/boe) 3.67 3.09
Royalties as a % of sales
after transportation 21% 19%
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TRUST UNITS
Trust units outstanding 78,496,581 79,216,046
Trust unit incentive rights outstanding 2,700,500 5,931,997
Units issuable for exchangeable shares 300,433 335,793
Units issuable for convertible debentures 5,390,625 5,390,625
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Diluted trust units outstanding 86,888,139 90,874,461
Diluted weighted average trust units(5) 78,985,481 75,792,488
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TRUST UNIT TRADING STATISTICS
(CDN$, except volumes) based on
intra-day trading
High 4.69 7.47
Low 1.17 2.76
Close 1.20 3.35
Average daily volume 270,458 492,004
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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.
Effective January 1, 2007 on adoption of CICA handbook sections 3855
and 3865, the Trust no longer applies hedge accounting to these
contracts. As such, these contracts are revalued to fair value at the
end of each reporting date. This results in recognition of unrealized
gains or losses over the term of these contracts which is reflected
each reporting period until these contracts are settled, at which
time realized gains or losses are recorded. These unrealized gains or
losses on commodity contracts are not included for purposes of per
unit metrics calculations disclosed.
(2) The highlights section contains the term "funds flow from
operations" (or as commonly referred to as "cash flow from
operations"), which should not be considered an alternative to, or
more meaningful than cash flow from operating activities as
determined in accordance with Canadian generally accepted accounting
principles ("GAAP") as an indicator of the Trust's performance.
Therefore reference to diluted funds flow from operations or funds
flow from operations per trust unit may not be comparable with the
calculation of similar measures for other entities. Management uses
funds flow from operations to analyze operating performance and
leverage and considers funds flow from operations to be a key measure
as it demonstrates the Trust's ability to generate the cash necessary
to fund future capital investments and to repay debt. The
reconciliation between funds flow from operations and cash flow from
operating activities can be found in the Management Discussion and
Analysis ("MD&A"). Funds flow from operations per trust unit is
calculated using the weighted average number of trust units for the
period.
(3) Net debt includes the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities and short-term
future income tax assets 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) Operating netbacks are calculated by subtracting royalties,
transportation, and operating costs from revenues.
(5) In computing weighted average diluted earnings per trust unit for the
year ended December 31, 2008 a total of 2,700,500 (2007: 5,931,997)
trust incentive units, 300,433 (2007: 335,793) exchangeable shares
and 5,390,625 (2007: 5,390,625) trust units issuable pursuant to the
conversion of convertible debentures were excluded from the
calculation for the years ended December 31, 2008 and 2007 as they
were not dilutive.
To calculate weighted average diluted funds flow from operations for
the year ended December 31, 2008, a total of 300,433 (2007: nil)
exchangeable shares were added to the denominator, resulting in
diluted weighted average trust units of 79,285,914 and funds flow
from operations per diluted trust unit of $0.98 under this
calculation. Under this calculation, a total of 2,700,500 (2007:
5,931,997) trust incentive units and 5,390,625 (2007: 5,390,625)
trust units issuable pursuant to the conversion of convertible
debentures were excluded from the calculation for the years ended
December 31, 2008 and 2007 as they were not dilutive.
REPORT TO UNITHOLDERS
True's Management and directors recognized, in 2006, the vulnerability
inherent with a weak balance sheet and set a goal of reducing the Company's
total net debt to ensure the Trust's long term financial flexibility. The
successful corporate strategy employed included divesting a segment of the
company's production base coupled with reducing distributions to $0.04 per
unit effective December 2007. These efforts culminated in the Trust decreasing
total net debt from $275.8 million in December 2006 by $60.8 million exiting
2008 with total net debt of $215.0 million. Unfortunately throughout the
second half of 2008 industry witnessed fierce erosion of commodity pricing
with an ensuing severe energy bear equity market. As a consequence the Trust
further decreased distributions in December 2008 to $0.02 per unit,
diminishing annual cash distribution paid in 2008 to $0.46 per unit.
Further on February 9, 2009 as economic conditions continued to
deteriorate driven by significant declining crude oil prices, a weakening
outlook for natural gas demand and heightened risk in the credit markets, the
Company deemed it prudent to suspend its distribution as of February 2009 to
maintain corporate liquidity during the current financial turmoil and
prevailing commodity price environment. Distributions continue to be reviewed
monthly in context of commodity prices, among other factors, and are subject
to revision by our Board of Directors.
True continues to also tighten the cost structure of our business with
forecasted cuts from 2008 levels of approximately 30% to total operating
expenses which includes general and administrative costs (G&A) and lease
operating costs in 2009. The Trust's capital program has been restricted to
$15 million and the Company is forecasting 2009 production volumes to average
approximately 10,000 boe/d.
Additional protection of the cash flow forecasts was achieved by hedging
approximately 60% of True's estimated 2009 natural gas production for the
period of March 1, 2009 to September 30, 2009 and 49% for the fourth quarter
of 2009 at a combined average fixed price of $6.42 CAD per GJ ($7.06/mcf), and
approximately 18% of True's estimated natural gas production is hedged for the
first half of 2010 at an average price of $7.25 CAD per GJ ($7.96/mcf). The
addition of a recent crude oil price collar effectively hedges approximately
13% of True's estimated 2009 crude oil production. True maintains an active
commodity price risk management program focused on maintaining sufficient cash
flow to fund its operations.
True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate
of $0.82, West Texas Intermediate ("WTI") oil price ranging from US$50.00/bbl
to US$55.00/bbl, AECO natural gas price ranging from CAD$5.00/GJ ($5.50/mcf)
to CAD$5.92/GJ ($6.50/mcf) and average annual production of approximately
10,000 boe/d generates cash flow from operations ranging from $30 million to
$40 million, after deducting royalties, all operating costs, G&A and debt
servicing costs. 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 55% of the Trust's forecasted
cash flow from operations on the low side case ensuring liquidity if commodity
prices continue to weaken.
Financial
Highlights:
1. Total net proceeds from the sale of properties in 2008 were
$44.3 million; which was used to pay down debt.
2. 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 December 31, 2008 was $215.0 million, down from
$250.3 million as at December 31, 2007 and $275.8 million as at
December 31, 2006. The convertible debentures have a maturity date of
June 30, 2011.
3. As at December 31, 2008, True has approximately $132.4 million drawn
on its extendible, revolving bank credit facility leaving
$19.6 million available to assist in managing our operations and
capital program.
4. The Trust and operating subsidiaries of the Trust have approximately
$495 million in tax pools available for deduction against future
income.
Funds flow from operations for the 2008 year was $77.9 million on gross
sales of $265.4 million compared to funds flow from operations of $101.2
million on gross sales of $258.5 million for the same period in 2007. The
decrease in funds flow for the 2008 year compared to 2007 was primarily the
result of lower sales volumes and higher realized hedging losses in 2008,
despite improved commodity pricing and operating netbacks.
Funds flow from operations for the 2008 fourth quarter was $5.9 million
on gross sales of $41.0 million compared to funds flow from operations of
$19.5 million on gross sales of $61.8 million for the same period in 2007.
This was reflective of lower commodity prices, lower sales volumes and higher
costs in 2008. Overall commodity prices for the fourth quarter of 2008
decreased significantly from that seen earlier in 2008 in connection with the
current global economic crisis. Crude oil prices in the month of December 2008
declined to a low of under US$40 WTI, a level not seen since 2004. Fourth
quarter 2008 funds flow from operations also includes $1.0 million of charges
associated with severance costs.
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.
The net loss for the 2008 year was $19.6 million compared to a net loss
of $24.3 million for 2007. The decrease in the net loss from 2007 to 2008 was
primarily due to reduced non-cash charges for depletion, depreciation and
accretion, higher unrealized gains on commodity contracts, offset by a reduced
future income tax recovery and lower funds flow from operations. The net loss
for the 2008 fourth quarter was $9.5 million compared to a net loss of $0.4
million in the same period in 2007. The net loss for the 2008 fourth quarter
was impacted by reduced funds flow from operations, partly offset by a $7.4
million unrealized mark-to-market gain on commodity contracts.
Liquidity
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.
The Trust generally relies on operating cash flows and the bank loan to
fund capital requirements and provide liquidity. From time to time, the Trust
accesses capital markets to meet its additional financing needs and to
maintain flexibility in funding its capital programs. Future liquidity depends
primarily on cash flow generated from operations, existing credit facilities
and the ability to access debt and equity markets.
The Trust's capital structure includes a revolving bank credit facility
and unsecured subordinated convertible debentures. The 7.5% unsecured
convertible debentures represents approximately 37% of the Trust's total net
debt and these debentures are due July 2011. Upon maturity or redemption of
these debentures, the Trust can be pay the outstanding principal or premium
(if any) in cash or, subject to regulatory approval, through the issuance of
additional Trust units at 95% of a weighted average trading price of the Trust
units. True's extendible, revolving bank credit facility was renewed on June
27, 2008 with an authorized loan amount of $152 million and consists of a $15
million demand operating facility and a $137 million extendible revolving term
syndicated credit facility. True's authorized loan amount was confirmed at
$152 million effective September 30, 2008 with the next borrowing base review
scheduled for March 31, 2009. The borrowing base will be subject to the
lending syndicate's determination which is based upon the latest reserves
information, their internal commodity price decks and other factors. In the
event the borrowing base is lowered below the drawn credit facility at that
time, any shortfall would be required to be repaid within 60 days of
notification, or as otherwise agreed by the lending syndicate, and this
funding would currently be expected to come from alternative sources of debt
or equity financing or the proceeds from asset dispositions as available. The
revolving period ends on June 26, 2009, unless extended for a further 364 day
period. Should the facilities not be renewed they convert to a 366 day
non-revolving credit facility. $12.5 million of the syndicated facility is
with a US bank which may be required to be repaid or reallocated to one or
more of the other four current members of the syndicate or a new member on
June 28, 2009. As at December 31, 2008, True had approximately $19.6 million
available under the facility to assist in managing our operations and capital
program. True is fully compliant with all of its debt covenants.
True's total net debt, excluding unrealized commodity contract assets and
liabilities, future income taxes and asset retirement obligations, as at
December 31, 2008, was $215.0 million, representing $132.4 million outstanding
on the credit facility, $81.1 million in convertible debentures (liability
component) and a $1.5 million working capital deficiency.
Combined funding requirements for distributions declared and True's
capital expenditures represented approximately 102% of funds flow from
operations in the twelve months ended December 31, 2008. Budgeted reduced
capital spending and distributions during the year mitigated the reduced
annual cash flows, primarily as a result of crude oil price declines
experienced in the later half of 2008.
There are currently no capital commitments, other than those associated
with the Trust's credit facilities outlined above and its 2009 drilling and
exploration program of $3 million for the first half of 2009. 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.
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 December 31, 2008, 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. This purchase is in response
to True's belief that the current market price for Trust units does not
reflect the underlying value of the Trust and the cancellation of the above
purchased Trust units will increase the proportionate interest of, and be
advantageous to, all remaining unitholders. Future repurchases will be
dependent on excess cash available after consideration of the Trust's priority
uses of cash and the trading price of the Trust's units relative to the net
asset value of the Trust.
In November 2008, the Trust received Toronto Stock Exchange approval for
its normal course issuer bid program to repurchase up to 10% of the issued and
outstanding 7.50% convertible unsecured subordinated debentures of the Trust
("Debentures") from December 1, 2008 to November 30, 2009. True believes that,
from time to time, the market price of the Debentures may not fully reflect
the underlying value of the Debentures and that at such times the purchase of
the Debentures would be in the best interests of the Trust. Such purchases
will increase the proportionate interest of, and may be advantageous to, all
remaining holders of Debentures as well as holders of Trust units. To date,
there have been no repurchases of the Debentures under this NCIB.
True does not hold any Asset-Backed Commercial Paper investments. As a
non-operating working interest owner, True has a minor exposure of
approximately $70,000 from oil sales marketed through SemCanada Crude Company,
which filed for CCAA protection on July 22, 2008. True does not have any
exposure to Lehman Brothers, which filed for Chapter 11 bankruptcy protection
in the United States. To the best of True's knowledge, the Trust does not have
any exposure to other US financial institutions.
True maintains an active commodity price risk management program. The
Trust will continue its hedging strategies focusing on maintaining sufficient
cash flow to fund True's operations.
In addition to the Trust's financial commodity risk management contracts,
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.
Property Acquisition and Dispositions
On October 1, 2008, True closed the purchase of further working interests
in the Mantario, Saskatchewan area for $4.3 million in cash after adjustments.
Effective October 1, 2008 this tuck-in acquisition added approximately 225
bbls/d of heavy oil production for metrics of $19,100/boe/d and $8.60/boe.
During the first quarter of 2008, True was successful in completing the
divestiture of a non-core property in Northeast Alberta for net proceeds of
$5.8 million. During the second quarter of 2008, True disposed of its
Dodsland-Stranraer property located in Saskatchewan for net proceeds of $38.5
million. Total net proceeds from the sale of properties in the 2008 were $44.3
million; the net proceeds from the dispositions were used to pay down debt.
Reserves and Production
Highlights from True's December 31, 2008 reserves include:
1. True's net asset value, based on GLJ Petroleum Consultants Ltd.
("GLJ") reserve report evaluation at a 10% discount rate, equates to
$4.98 per unit and $4.96 per fully diluted unit.
2. The Trust's reserves life index has extended to 6.4 years for proved
reserves and 10.1 years for proved plus probable reserves.
3. The Trust recorded all-in annual Finding, Development and Acquisition
("FD&A") cost of $18.20 per barrel of oil equivalent ("boe") in 2008
before consideration of future development capital ("FDC") for proved
reserves category. This is a 51 percent reduction from the $37.30 per
boe FD&A cost realized in 2007. Including FDC, the FD&A cost was
$20.90 per boe. The three year average FD&A cost is $36.70 per boe
for the proved category before FDC; including FDC, the three year
average FD&A cost is $30.40 per boe.
4. The Trust established a recycle ratio, after hedging and excluding
future development costs, of 1.34x on a proved basis and 0.77x on a
proved and probable basis.
5. Total proved plus probable Company Interest Reserves, including all
royalties receivable but before deducting royalty burdens, as
evaluated by GLJ at December 31, 2008 were 39,488 mboe (gas
converted 6:1).
6. Based on the reserves information and other data as at December 31,
2008, the Trust has performed ceiling test calculations in accordance
with the requirements of CICA AcG 16 "Oil and Gas Accounting - Full
Cost." No ceiling test impairment of oil and gas properties was
identified for accounting purposes as at December 31, 2008.
For additional information please refer to the reserves news release
dated February 9, 2009 (posted on www.sedar.com).
For the 2008 year, sales volumes averaged 11,867 boe/d compared to 14,937
boe/d that was produced in Q4 of 2007. The reduction in average sales volumes
is a result of natural production decline, minimal 2008 capital spending and
the impact of dispositions totaling approximately 1,000 boe/d that were closed
during the first half of 2008. Effective October 1, 2008, True closed the
purchase of further working interests in the Mantario, Saskatchewan area for
$4.3 million in cash after adjustments. This tuck in acquisition added
approximately 225 bbls/d of heavy oil production for metrics of $19,100 per
boe/d.
2008 fourth quarter sales volumes averaged 10,750 boe/d. True's
production and operations have been negatively impacted by the extreme weather
conditions experienced in western Canada in December 2008 and extending into
January 2009.
Based on minimal capital spending, and normal production declines, 2009
production volumes are anticipated to average approximately 10,000 boe/d.
Drilling
During the 2008 year, True had an interest in a total of 38 (17.1 net)
wells drilled, which resulted in 7.1 net natural gas wells, 4.0 net light oil
wells, 0.8 net heavy oil well and 1.0 net water disposal well. 4.2 net wells
were dry and abandoned.
Included in the above were nine gross natural gas wells that evaluated
True land at no cost to the Company. In eight True has an overriding royalty;
in the other True has no capital cost to drill, complete and tie in, retaining
a 20% working interest from first production. True has over 377,000 net acres
of undeveloped mineral leases in Alberta, British Columbia and Saskatchewan as
of December 31, 2008. An integral component of our growth strategy is to
aggressively farmout our interest in non core areas.
During the fourth quarter of 2008, True drilled or participated in 10
(5.1 net) wells including 3.1 net natural gas wells, and 2.0 net light oil
wells. Fourth quarter drilling was focused on the Kerrobert Viking horizontal
light oil wells in Kindersley and conventional natural gas drilling at Saddle
Lake in North East Alberta. 1.0 net wells from the Saddle Lake drilling
program are expected to be tied in during the first quarter of 2009.
During the fourth quarter of 2008, True was successful in farming out its
interest in 12,700 net acres located in British Columbia. The arrangement will
see True carried through the drilling and completion phases of the program
with the ability to retain a small working interest and remain involved in a
key high impact, high cost Montney play.
Disposition of Working Interest in Block 126 Peru
As announced on November 24, 2008, True and Petrominerales Ltd.
(TSX:PMG), a 76.4% owned subsidiary of Petrobank Energy and Resources Ltd.,
have entered into an agreement whereby Petrominerales will acquire True's 10%
working interest and will be designated the operator of Block 126 located in
the Ucayali Basin of east central Peru. A wholly-owned subsidiary of True held
the 10% working interest and is the operator in a partnership with Veraz
Petroleum Ltd. ("Veraz"). Closing of this transaction is subject to the
consent of Perupetro S.A, the private law state company responsible for
promoting the investment of hydrocarbon exploration and exploitation
activities in Peru and receipt of the purchase price according to the
agreement. True continues to have a minor investment in Veraz.
2009 Outlook
The global economic contraction has caused oil and gas prices to plummet
producing both, a sector wide severe bear equity market and substantially
decreasing cash flow. The consequences are being felt industry wide with
slashed capital programs coupled with suppressed expense budgets. True has
adopted a very cautious outlook with material reductions in its operating cost
base.
True has targeted reductions in general and administrative expenses early
in 2009 and we will continue to focus on opportunities to reduce operating
costs. As part of the general and administrative cost reductions, True has
streamlined its operations and reduced head office staffing levels by a third.
True has forecasted cuts of 30% to total operating expenses, which includes
general and administrative costs and lease operating costs, in 2009. Cost
reductions in combination with limiting our capital spending in the first half
of 2009 will add to our financial flexibility and better position True to
operate in the current difficult economic environment.
True does not intend to drill any operated wells in the first half of
2009. Furthermore, capital spending will be limited to $3 million during the
first six months of 2009. In addition to focusing on increasing production
from existing wells through continued optimization, and performing necessary
maintenance programs, the first half 2009 capital spending will be limited to
the tie-in of two gross (1 net) Saddle Lake area natural gas wells drilled in
the fourth quarter of 2008. Non-operated projects will continue to be closely
scrutinized against internal opportunities. True's total 2009 capital program
is not expected to exceed $15 million and will reflect our future view of
commodity pricing and cash flow, available business opportunities, and
industry costs trends.
The Company has reorganized its senior management with the appointment of
myself as President and CEO, Mr. Russell G. Oicle as Vice President,
Exploration and Mr. Duncan A. Chisholm, as Vice President, Operations. This
group brings in excess of 100 years of experience and expertise to True as
successful full cycle explorationists and production optimization specialists.
With a cautious bias to cost control, the Company will proceed in 2009 to
explore its quality land base while high grading the plethora of low risk
development opportunities.
A conference call to discuss True's annual financial and reserves results
will be held on March 17, 2009 at 2:00 PM MDT/4:00 PM EDT. To participate,
please call toll-free 1-800-731-5774 or 416-644-3423. The conference call will
also be recorded and available by calling 1-877-289-8525 or 416-640-1917 and
entering passcode 21295355 followed by the pound sign.
True's annual general meeting is scheduled for 3:00pm on May 20, 2009 in
the Herald Doll Room at the Hyatt Regency in Calgary.
Raymond G. Smith, P. Eng.
President and CEO
March 16, 2009
MANAGEMENT'S DISCUSSION AND ANALYSIS
March 16, 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 audited consolidated
financial statements of the Trust for the years ended December 31, 2008 and
2007. This commentary is based on information available to, and is dated as
of, March 16, 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 funds flow from operations and cash flow from
operating activities can be found in the Management's Discussion and Analysis.
Funds flow from operations per unit is calculated using the weighted average
number of units for the period.
This Management's Discussion and Analysis also contains other terms such
as 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 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 production rates,
hedging strategies, distributions and method of funding thereof, anticipated
liquidity of the Trust and various matters that may impact such liquidity,
timing of bringing production back on from certain wells, 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 netbacks in 2009 compared
to 2008, proportion of distributions anticipated to be taxable and
non-taxable, maintenance of productive capacity and capital expenditures and
the nature of capital expenditures and the timing and method of financing
thereof, may constitute forward-looking statements under applicable securities
laws and necessarily involve risks including, without limitation, risks
associated with oil and gas exploration, development, exploitation,
production, marketing and transportation, loss of markets, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other producers, inability to retain
drilling rigs and other services, incorrect assessment of the value of
acquisitions, failure to realize the anticipated benefits of acquisitions,
delays resulting from or inability to obtain required regulatory approvals and
ability to access sufficient capital from internal and external sources. The
recovery and reserve estimates of True's reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered. Events or circumstances may cause actual results to differ
materially from those predicted, as a result of the risk factors set out and
other known and unknown risks, uncertainties, and other factors, many of which
are beyond the control of True. In addition, forward-looking statements or
information are based on a number of factors and assumptions which have been
used to develop such statements and information but which may prove to be
incorrect. 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
financial outlook was approved by management of the Trust on February 9, 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 distribution 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.
Fourth Quarter 2008
Funds flow from operations during the fourth quarter of 2008 was $5.9
million, a decrease of 70% compared to $19.5 million for the fourth quarter of
2007. This was reflective of lower commodity prices, lower sales volumes and
higher costs in 2008. Overall commodity prices for the fourth quarter of 2008
decreased significantly from that seen earlier in 2008 in connection with the
current global economic crisis. Crude oil prices in the month of December 2008
declined to a low of under US$40 WTI, a level not seen since 2004. Fourth
quarter 2008 funds flow from operations also includes $1.0 million of charges
associated with severance costs. By comparison, in the last quarter of 2008,
True had a net loss of $9.5 million compared to a net loss of $0.4 million in
the fourth quarter of 2007.
Sales volumes for the three months ended December 31, 2008 averaged
10,750 boe/d, down 28% from the 14,937 boe/d produced in the fourth quarter of
2007. Fourth quarter 2008 sales volumes were lower than the same period in
2007 due to natural production declines, decreased production due to property
dispositions during 2008, extreme weather conditions, and minimal capital
spending.
In the fourth quarter of 2008, average sales volumes decreased 5% from
the third quarter 2008 average volumes of 11,263 boe/d. True's production and
operations were impacted by the extreme weather conditions and commodity price
erosion experienced in western Canada in December 2008 and extending into
January 2009. True realized the loss of an estimated 950 boe/d which was
directly related to both weather and True's ongoing review of profitability.
True continues to apply good winter operating practices to remedy the offline
production, however, an estimated 250 boe/d will be reactivated upon receiving
improved commodity prices. Natural gas sales averaged 38.4 Mmcf/d during the
last quarter of 2008, compared to 57.4 Mmcf/d in the fourth quarter of 2007.
The Trust's natural gas sales reduction was in part attributed to a
Saskatchewan asset divestiture. The weighting toward natural gas averaged 60%
in the fourth quarter, compared to 64% in the corresponding period of 2007.
Crude oil, condensate and NGL sales volumes averaged 4,347 bbls/d in the
fourth quarter of 2008 compared to 5,370 bbls/d during the same period of
2007.
During the fourth quarter of 2008, True spent $11.0 million on capital
projects, excluding corporate and asset acquisitions and dispositions,
compared to $15.5 million in 2007. In the fourth quarter of 2008, True drilled
or participated in 10 (5.1 net) wells including 3.1 net natural gas wells, and
2.0 net light oil wells. Fourth quarter drilling was focused on the Kerrobert
Viking horizontal light oil wells in Kindersley and conventional natural gas
drilling at Saddle Lake in North East Alberta. 1.0 net well from the Saddle
Lake drilling program is expected to be tied in during the first quarter of
2009. Also, during the fourth quarter of 2008, True was successful in farming
out its interest in 12,700 net acres located in British Columbia. The
arrangement will see True carried through the drilling and completion phases
of the program with the ability to retain a small working interest and remain
involved in a key Montney formation play.
During the fourth quarter of 2008, True experienced an overall decrease
of 41% in commodity prices, based on decreases in crude oil, condensate and
NGL pricing, as compared to the same period in 2007. The average daily and
monthly AECO indices for natural gas during this quarter was 9% and 13%,
respectively, higher than in the same period in 2007. For the three months
ending December 31, 2008, True received an average natural gas price, before
transportation and hedging, of $6.98/Mcf, 9% higher than $6.40/Mcf in the same
period in 2007 and 22% lower than $8.97/Mcf in the third quarter of 2008. For
heavy crude oil, True received an average price before transportation of
$36.52/bbl during the fourth quarter of 2008, 8% less than $39.72/bbl in the
same period in 2007 and 61% less than $92.51/bbl in the third quarter of 2008.
In comparison, the average reference price for Hardisty Heavy crude in the
fourth quarter of 2008 was 12% less than the average 2007 price in the same
period. For light oil, condensate and NGLs, True received an average price of
$45.96/bbl before transportation and hedging during the last quarter of 2008,
41% less than the average price of $78.42/bbl received in the same period of
2007, compared to a 27% decrease in the Edmonton par reference price. The
average price for light oil, condensate and NGLs for True was 57% lower than
the $107.55/bbl for the third quarter of 2008. During the fourth quarter of
2008, revenue before other income and hedging of $40.2 million was 33% lower
than the corresponding 2007 period.
In the fourth quarter of 2008, the Trust paid $9.0 million in royalties,
compared to $12.6 million in the same period in 2007. As a percentage of
pre-hedge sales (after transportation costs), royalties were 23% in the fourth
quarter of 2008 compared to 22% in the same period in 2007. In this same
period of 2008, operating costs totaled $17.9 million, compared to $16.5
million recorded in the same period of 2007. During the fourth quarter of
2008, operating costs averaged $18.11/boe, up from the $12.01/boe incurred
during the fourth quarter of 2007. The increase was due to a number of factors
including incremental unanticipated prior period cost adjustments from
non-operated properties and additional workover and other costs from earlier
in 2008. Also, fuel gas costs associated with steam generation at the
Kerrobert facility contributed $1.57/boe in the fourth quarter of 2008,
whereas these costs were capitalized in 2007 during initial steaming period
for the project expansion. In addition, the fixed component of certain
operating costs combined with reduced sales volumes between comparable periods
has contributed to the increase in costs on a per boe basis. In comparison,
operating costs for the third quarter of 2008 averaged $14.95/boe. True is
targeting operating costs of approximately $48.8 million ($13.40/boe) in 2009.
This is based upon assumptions of estimated production of approximately 10,000
boe/d and planned cost reductions. During the fourth quarter of 2008, company
field operating netbacks decreased by 40% to $12.31/boe compared to 2007,
driven primarily by decreased overall commodity prices and increased operating
costs. In comparison, the company field operating netback for the third
quarter of 2008 was $38.31/boe. Field operating netbacks for natural gas
before hedging during the fourth quarter of 2008 of $2.35/Mcf were 15% less
than the 2007 netbacks, reflecting higher royalties and production costs,
somewhat offset by higher commodity prices and reduced transportation costs.
In comparison, the field operating netback for natural gas for the third
quarter of 2008 was $5.50/Mcf. Field operating netbacks before hedging for
crude oil, condensate and NGLs during the fourth quarter of 2008 averaged
$9.68/bbl, down from $27.34/bbl during the fourth quarter of 2007, primarily
as a result of a significant decrease in the overall commodity price received,
and with higher production expenses partially offset by a reduction in
royalties. In comparison, the field operating netback for crude oil,
condensate and NGLs for the third quarter of 2008 was $48.07/bbl.
In the fourth quarter of 2008, the net cost of general and administrative
expenses was $4.1 million, compared to $4.7 million in the comparable 2007
period reflecting a reduction of the number of salaried personnel on staff and
other efforts to reduce costs. Fourth quarter 2008 general and administrative
costs include $1.0 million of charges associated with severance costs. True is
forecasting general and administrative costs of approximately $11.5 million
($3.15/boe) in 2009 based on the cost reduction initiatives applied in early
January and estimated 2009 production volumes of approximately 10,000 boe/d.
This represents an approximate 30% reduction over 2008 costs.
Depletion, depreciation and accretion expense for the fourth quarter of
2008 was $29.4 million, compared to $39.8 million in 2007, which reflects
reduced carrying costs in 2008, combined with lower production volumes in
fourth quarter 2008 versus 2007.
2008 Annual Financial and Operational Results
Net Loss and Funds Flow from Operations
True generated funds flow from operations of $77.9 million ($0.98 per
diluted unit) for the year ended December 31, 2008, down 23% from $101.2
million ($1.33 per diluted unit) for the 2007 year. The decrease in funds
flow for the 2008 year compared to 2007 was primarily the result of lower
sales volumes and higher realized hedging losses, despite improved commodity
pricing and operating netbacks.
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.
The net loss for the 2008 year was $19.6 million ($0.25 per diluted unit)
compared to a net loss of $24.3 million ($0.32 per diluted unit) in 2007. The
decrease in the net loss from 2007 to 2008 was primarily due to reduced
non-cash charges for depletion, depreciation and accretion, higher unrealized
gains on commodity contracts, offset by a reduced future income tax recovery
and lower funds flow from operations.
Funds Flow From Operations and Net Loss
-------------------------------------------------------------------------
Years Ended December 31,
($000s, except per unit amounts) 2008 2007
-------------------------------------------------------------------------
Funds flow from operations 77,893 101,172
Basic ($/unit) 0.99 1.33
Diluted ($/unit) 0.98 1.33
Net loss (19,590) (24,267)
Basic ($/unit) (0.25) (0.32)
Diluted ($/unit) (0.25) (0.32)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Reconciliation of Funds Flow from Operations and Cash Flow from
Operating Activities
-------------------------------------------------------------------------
Years ended December 31,
($000s, except per unit amounts) 2008 2007
-------------------------------------------------------------------------
Funds flow from operations 77,893 101,172
Asset retirement costs incurred (2,603) (835)
Change in non-cash working capital 3,494 (18,131)
-------------------------------------------------------------------------
Cash flow from operating activities 78,784 82,206
-------------------------------------------------------------------------
Sales Volumes
Sales volumes for the year ended December 31, 2008 averaged 11,867 boe/d
compared to 16,139 boe/d for the same period in 2007, representing a 26%
decrease.
In addition to natural production decline and minimal 2008 capital
spending, year over year production volumes were impacted by dispositions
totalling approximately 1,000 boe/d that were closed during the first half of
2008. Also, approximately 950 boe/d was affected in the fourth quarter of 2008
(approximately 240 boe/d annualized) due to extreme weather conditions causing
delayed servicing and freeze offs.
On October 1, 2008, True closed the purchase of further working interests
in the Mantario, Saskatchewan area for $4.3 million in cash after adjustments.
Effective October 1, 2008 this tuck-in acquisition adds approximately 225
bbls/d of heavy oil production for metrics of $19,100/boe/d and $8.60/boe.
Sales Volumes
-------------------------------------------------------------------------
Years ended December 31,
2008 2007
-------------------------------------------------------------------------
Natural gas (mcf/d) 45,202 64,853
-------------------------------------------------------------------------
Heavy oil (bbls/d) 2,897 3,450
Light oil and condensate (bbls/d) 999 1,289
NGLs (bbls/d) 437 591
-------------------------------------------------------------------------
Total crude oil and NGLs (bbls/d) 4,333 5,330
-------------------------------------------------------------------------
Total boe/d (6:1) 11,867 16,139
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the 2008 year, True had an interest in a total of 38 wells (17.1
net) drilled, which resulted in 7.1 net natural gas wells, 4.0 net light oil
wells, 0.8 net heavy oil well and 1.0 net water disposal well. 4.2 net were
dry and abandoned.
Included in the above were nine gross natural gas wells that evaluated
True land at no cost to the Company. In eight True has an overriding royalty;
in the other True has no capital cost to drill, complete and tie in, retaining
a 20% working interest from first production. True has over 377,000 net acres
of undeveloped mineral leases in Alberta, British Columbia and Saskatchewan as
of December 31, 2008. An integral component of our growth strategy is to
aggressively farmout our interest in non core areas.
By comparison, True drilled or participated in 40 (27.3 net) working
interest wells in 2007.
For the year ended December 31, 2008, the weighting towards natural gas
sales averaged 63% compared to 67% for the 2007 year. Heavy oil sales made up
24% of total production for the 2008 year compared to 21% in 2007.
Sales of natural gas averaged 45.2 Mmcf/d for 2008, compared to 64.9
Mmcf/d in 2007, a decrease of 30%. Crude oil and NGL sales for 2008 decreased
19% averaging 4,333 bbls/d compared to 2007 average sales of 5,330 bbls/d.
2009 production volumes are anticipated to average approximately 10,000
boe/d. The forecast of 2009 production volumes is based upon a number of
assumptions, including normal production declines and expenditures under the
current planned capital budget of $15 million.
Commodity Prices
Average Commodity Prices
-------------------------------------------------------------------------
Years ended December 31,
2008 2007 % Change
-------------------------------------------------------------------------
Exchange rate (US$/Cdn$) 0.9372 0.9390 -%
Natural gas:
NYMEX (US$/mmbtu) 8.89 7.14 25%
AECO daily index (CDN$/Mcf) 8.13 6.44 26%
AECO monthly index (CDN$/Mcf) 8.12 6.61 23%
True's average price ($/mcf) 8.50 6.73 26%
True's average price
(including hedging(1)) ($/mcf) 8.00 7.08 13%
Crude oil:
WTI (US$/bbl) 99.73 74.25 34%
Edmonton par - light oil ($/bbl) 102.85 77.06 33%
Bow River - medium/heavy oil ($/bbl) 83.85 53.16 58%
Hardisty Heavy - heavy oil ($/bbl) 76.32 44.77 70%
True's average prices ($/bbl)
Light crude oil, condensate, and NGLs 88.42 64.60 37%
Heavy crude oil 70.96 40.05 77%
Total crude oil and NGLs 76.75 48.71 58%
Total crude oil and NGLs
(including hedging(1)) 64.24 47.74 35%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 2008, the AECO daily and monthly reference price
increased by 26% and 23%, respectively, compared to the same period in 2007.
Similarly, True's average sales price before hedging for 2008 increased by 26%
compared to the same period in 2007. True's natural gas price after including
hedging for 2008 was $8.00/mcf compared to $7.08/mcf for 2007.
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 $70.96/bbl for 2008, an increase of 77% over prices in the 2007 year. The
Bow River reference price increased by 58% and the Hardisty Heavy reference
price increased by 70% over the same period. The majority of True's heavy
crude oil density ranges between 11 and 16 degrees API consistent with the
Hardisty Heavy reference price, although all of True's heavy oil production is
sold at Saskatchewan delivery points. During 2008, the blending costs for
condensate were lower which has also contributed to higher pricing received
For light oil, condensate and NGLs, True recorded an average $88.42/bbl
before hedging during 2008, 37% higher than the average price received in the
2007 year. In comparison, the Edmonton par price increased by 33% over the
same period. The average WTI crude oil US dollar based price increased 34%
from 2007 to 2008. True's realized price after including hedging was
$126.14/bbl for 2008 compared to $45.22/bbl for the same period in 2007.
Although oil prices achieved record highs throughout 2008, peaking in July at
US$147.27 per barrel of for WTI and averaging US$99.73 per barrel for the full
year, the sharp decline in oil prices during the fourth of 2008 has resulted
in exit 2008 oil prices at their lowest level since 2004. The full impact of
the price decline will not be realized until the first quarter of 2009. The
average US$/Cdn$ foreign exchange rate was 0.94 for the full year of 2008;
however, a sharp decline in the fourth quarter resulted in the U.S. dollar
closing at 0.83 per Canadian dollar on December 31, 2008. The negative
correlation between the Canadian dollar and U.S. dollar denominated WTI oil
prices should lessen the impact on the Trust of any future declines in the
price of oil, however, crude oil prices have remained depressed in the early
part of 2009 and investors should expect that revenues in 2009 will be
significantly lower than those recorded in 2008.
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. 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 year ended December 31,
2008 was $262.4 million, 3% higher than the $254.0 million in the same period
in 2007. The higher revenue for the 2008 period was the result of
significantly higher commodity prices, despite lower sales volumes.
-------------------------------------------------------------------------
Years ended December 31,
($000s) 2008 2007
-------------------------------------------------------------------------
Light crude oil, condensate and NGLs 46,485 44,325
Heavy oil 75,241 50,436
-------------------------------------------------------------------------
Crude oil and NGLs 121,726 94,761
Natural gas 140,701 159,278
-------------------------------------------------------------------------
Total revenue before other 262,427 254,039
Other(1) 2,958 4,451
-------------------------------------------------------------------------
Total revenue before royalties and hedging 265,385 258,490
-------------------------------------------------------------------------
(1) Other revenue primarily consists of processing and other third party
income.
Revenues for 2009 are currently expected to be lower than 2008 due to
lower commodity prices and average estimated 2009 production of approximately
10,000 boe/d.
Commodity Price Risk Management
The Trust has a formal risk management policy which permits management to
use specified price risk management strategies for up to 50% of crude oil,
natural gas and NGL production including fixed price contracts, collars and
the purchase of floor price options and other derivative financial instruments
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 March 16, 2009 is shown in the following tables:
Natural gas
Average Volumes (GJ/d)
-------------------------------------------------------------------------
Q1 2009 Q2 2009 Q3 2009 Q4 2009
-------------------------------------------------------------------------
Fixed 15,544 20,050 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)
-------------------------------------------------------------------------
Q1 2009 Q2 2009 Q3 2009 Q4 2009
-------------------------------------------------------------------------
Fixed 6.94 6.01 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)
-------------------------------------------------------------------------
Q1 2009 Q2 2009 Q3 2009 Q4 2009
-------------------------------------------------------------------------
Costless collars 172 500 500 500
-------------------------------------------------------------------------
Total bbls/d 172 500 500 500
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average Price (US$/bbl WTI)
-------------------------------------------------------------------------
Q1 2009 Q2 2009 Q3 2009 Q4 2009
-------------------------------------------------------------------------
Collar ceiling price 65.60 65.60 65.60 65.60
Collar floor price 42.50 42.50 42.50 42.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Included in the above natural gas table is a fixed price contract of
$5.90/GJ at 5,000 GJ/d for the Q2 2009 to Q4 2009 periods which was funded by
selling a call option of 5,000 GJ/d at $8.05 for the 2010 year.
As of December 31, 2008, the fair value of True's outstanding commodity
contracts is an unrealized asset of $3.7 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 December 31, 2008 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.
Strong commodity prices throughout most of 2008 had a significant impact
on the Trust's revenue; however, these strong prices resulted in realized cash
losses of $19.8 million and $8.4 million for the Trust's oil and natural gas
risk management contracts, respectively.
The following is a summary of the gain (loss) on commodity contracts for
the years ended December 31, 2008 and 2007 as reflected in the Consolidated
Statements of Loss in the financial statements:
Commodity contracts
-------------------------------------------------------------------------
Crude Oil Natural
($000s) & Liquids Gas 2008 Total
-------------------------------------------------------------------------
Realized cash loss on contracts (19,835) (8,387) (28,222)
Unrealized gain on contracts(2) 11,404 2,664 14,068
-------------------------------------------------------------------------
Total loss on commodity contracts (8,431) (5,723) (14,154)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Crude Oil Natural
($000s) & Liquids Gas 2007 Total
-------------------------------------------------------------------------
Realized cash gain (loss)
on contracts(1) (1,891) 8,382 6,491
Unrealized gain (loss)
on contracts(2) (11,404) 1,061 (10,343)
-------------------------------------------------------------------------
Total gain (loss) on
commodity contracts (13,295) 9,443 (3,852)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes the crude oil and natural gas commodity contract premium
expenses and the amortization of prior year crude oil and natural gas
commodity contract premiums of a total $3.7 million for the year
ended December 31, 2007.
(2) Unrealized gain (loss) commodity contracts represent non-cash
adjustments for changes in the fair value of these contracts during
the period.
Royalties
For the year ended December 31, 2008, total royalties were $54.6 million,
compared to $47.0 million incurred in 2007. Overall royalties as a percentage
of revenue (after transportation costs) in 2008 were 21%, compared with 19% in
2007. Royalties were lower by approximately $5.5 million in 2007 due to the
reversal of certain prior period over accruals for light and heavy crude oil
royalties; excluding these adjustments, the average royalty rate for the year
ended December 31, 2007 would have been 20%.
-------------------------------------------------------------------------
Royalties by Commodity Type Years ended December 31,
($000s, except where noted) 2008 2007
-------------------------------------------------------------------------
Light crude oil, condensate and NGLs 11,211 9,772
$/bbl 21.33 14.24
Average light crude oil, condensate and NGLs
royalty rate (%) 25 22
Heavy Oil 14,060 6,867
$/bbl 13.26 5.45
Average heavy oil royalty rate (%) 20 14
Natural Gas 29,291 30,365
$/mcf 1.77 1.28
Average natural gas royalty rate (%) 21 20
-------------------------------------------------------------------------
Total 54,562 47,004
-------------------------------------------------------------------------
$/boe 12.56 7.98
-------------------------------------------------------------------------
Average total royalty rate (%) 21 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Royalties, by Type
-------------------------------------------------------------------------
Years ended December 31,
($000s) 2008 2007
-------------------------------------------------------------------------
Crown royalties 30,354 20,799
Indian Oil and Gas Canada royalties 6,479 5,927
Freehold & GORR 17,729 20,278
-------------------------------------------------------------------------
Total 54,562 47,004
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Expenses
-------------------------------------------------------------------------
Years ended December 31,
($000s) 2008 2007
-------------------------------------------------------------------------
Production 66,573 68,282
Transportation 7,047 7,938
General and administrative 15,958 18,186
Interest and financing charges 14,822 18,108
Unit-based compensation 1,395 2,001
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Expenses per boe
-------------------------------------------------------------------------
Years ended December 31,
($ per boe) 2008 2007
-------------------------------------------------------------------------
Production 15.33 11.59
Transportation 1.62 1.35
General and administrative 3.67 3.09
Interest and financing charges 3.41 3.07
Unit-based compensation 0.32 0.34
-------------------------------------------------------------------------
Production Expenses
For the year ended December 31, 2008, production expenses totaled $66.6
million ($15.33/boe), compared to $68.3 million ($11.59/boe) recorded in 2007.
The increase in production expenses in 2008 on a boe basis is due to a number
of factors. Repairs and operating workovers for 2008 were approximately $15.6
million ($3.59/boe) compared to $19.1 million ($3.24/boe) in 2007. Also, fuel
gas costs associated with steam generation at the Kerrobert facility
contributed $1.91/boe in 2008, whereas these costs were capitalized in late
2007 during initial steaming period for the project expansion. In addition,
the fixed component of certain production expenses combined with reduced sales
volumes between comparable periods has contributed to the increase in costs on
a per boe basis. True is targeting operating costs of approximately $48.8
million ($13.40/boe) in 2009. This is based upon assumptions of estimated
production of approximately 10,000 boe/d and planned cost reductions.
Production Expenses, by Commodity Type
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2008 2007
-------------------------------------------------------------------------
Light crude oil, condensate and NGLs 10,155 9,906
$/bbl 19.32 14.44
Heavy oil 22,672 18,301
$/bbl 21.38 14.53
Natural gas 33,746 40,075
$/mcf 2.04 1.69
-------------------------------------------------------------------------
Total 66,573 68,282
-------------------------------------------------------------------------
$/boe 15.33 11.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 66,573 68,282
-------------------------------------------------------------------------
Processing and other third party income(1) (2,958) (4,451)
-------------------------------------------------------------------------
Total after deducting processing and other third
party income 63,615 63,831
-------------------------------------------------------------------------
$/boe 14.65 10.84
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(1) Processing and other third party income is included within petroleum
and natural gas sales on the statement of income.
Transportation
Transportation expenses have historically been approximately 2% to 3% of
gross revenues. For the years ended December 31, 2008 and 2007, transportation
expenses averaged approximately 3%.
Operating Netback
For the 2008 year, corporate field operating netback (before hedging) was
$30.91/boe compared to $22.21/boe in fiscal 2007. This was the result of
increased overall commodity prices, partially offset by higher transportation,
royalties and operating costs experienced in 2008. After including hedging
activities, the corporate field operating netback for 2008 was $24.41/boe
compared to $23.31/boe in 2007.
Field Operating Netback - Corporate (before hedging)
-------------------------------------------------------------------------
For the years ended December 31,
($/boe) 2008 2007
-------------------------------------------------------------------------
Sales 60.42 43.13
Transportation (1.62) (1.35)
Royalties (12.56) (7.98)
Production expense (15.33) (11.59)
-------------------------------------------------------------------------
Field operating netback 30.91 22.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 2008 increased 30% to
$4.52/mcf, compared to $3.47/mcf in 2007, reflecting stronger natural gas
prices experienced, the effects of which were partially offset by higher
royalties and transportation expenses. After including hedging activities,
field operating netback for natural gas for fiscal 2008 was $4.02/mcf compared
to $3.83/mcf in the same period in 2007.
Field Operating Netback - Natural Gas (before hedging)
-------------------------------------------------------------------------
Years ended December 31,
($/mcf) 2008 2007
-------------------------------------------------------------------------
Sales 8.50 6.73
Transportation (0.17) (0.29)
Royalties (1.77) (1.28)
Production expense (2.04) (1.69)
-------------------------------------------------------------------------
Field operating netback 4.52 3.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Field operating netback for crude oil, condensate and NGLs averaged
$37.46/bbl for 2008, up 50% compared to $25.01/bbl for 2007. This compares to
a 58% increase in the crude oil, condensate and NGLs sales price combined with
an increase in overall expenses over the same period. After including hedging
activities, field operating netback for crude oil and NGLs for 2008 was
$24.96/boe compared to $24.04/boe in 2007.
Field Operating Netback - Crude Oil, Condensate and NGLs (before hedging)
-------------------------------------------------------------------------
Years ended December 31,
($/bbl) 2008 2007
-------------------------------------------------------------------------
Sales 76.75 48.71
Transportation (2.66) (0.65)
Royalties (15.93) (8.55)
Production expense (20.70) (14.50)
-------------------------------------------------------------------------
Field operating netback 37.46 25.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
General and Administrative
Net general and administrative ("G&A") expenses for 2008 were $16.0
million compared to $18.2 million for 2007. The decrease in the G&A expense
for the year ended December 31, 2008 from the same period in 2007 reflects a
reduction of the number of salaried personnel on staff and other efforts to
reduce costs. G&A costs for the year includes $1.0 million of charges
associated with severance costs in the fourth quarter of 2008. The reduction
in amounts of capitalized G&A for 2008 is consistent with a lower capital
program. On a per boe basis, G&A expenses for fiscal 2008 were $3.67/boe
compared to $3.09/boe for fiscal 2007. The increase in G&A on a per boe basis
is consistent with reduced sales volumes experienced in 2008 compared to 2007.
True had targeted reductions in G&A expenses in early 2009. As part of
the G&A cost reductions, True has streamlined its operations and reduced head
office staffing levels and costs by approximately one third. For 2009, the
Trust is anticipating G&A costs to be approximately $11.5 million ($3.15/boe)
based on the cost reduction initiatives applied in early January 2009 and
estimated 2009 production volumes of approximately 10,000 boe/d.
General and Administrative Expenses
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2008 2007
-------------------------------------------------------------------------
Gross expenses 20,197 24,191
Capitalized (2,419) (3,881)
Recoveries (1,820) (2,124)
-------------------------------------------------------------------------
Net expenses 15,958 18,186
-------------------------------------------------------------------------
Net expenses, per unit ($/boe) 3.67 3.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest and Financing Charges
True recorded $14.8 million of interest and financing charges for the
year ended December 31, 2008 compared to $18.1 million in 2007. True's total
net debt at December 31, 2008 of $215.0 million includes the $81.1 million
liability portion of convertible debentures, $132.4 million of bank debt and
the net balance of working capital. The convertible debentures have a maturity
date of June 30, 2011.
Interest and Financing Charges
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2008 2007
-------------------------------------------------------------------------
Interest and financing charges 14,822 18,108
Interest and financing charges ($/boe) 3.41 3.07
Debt to funds flow from operations ratio
annualized
Total net debt(1) at year end 215,004 250,313
Total net debt to periods funds flow from
operations ratio annualized(2) 9.2x 3.2x
Net debt(1) (excluding convertible debentures) at
year end 133,880 171,006
Net debt to periods funds flow from operations
ratio annualized(2) 5.7x 2.2x
Debt to funds flow from operations ratio
Total net debt(1) at year end 215,004 250,313
Total net debt to funds flow from operations ratio 2.8x 2.5x
Net debt(1) (excluding convertible debentures) at
year end 133,880 171,006
Net debt to funds flow from operations ratio 1.7x 1.7x
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net debt includes the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities 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) Debt to funds flow from operations ratio annualized is calculated
based upon fourth quarter funds flow from operations annualized.
Unit-Based Compensation
Non-cash unit-based compensation expense for the year ended December 31,
2008 was $1.4 million compared to $2.0 million in 2007. The 2008 expense
reflects a reduction in the estimated weighted average fair value of incentive
rights granted for more recent options and a reduction to the 2008 expense of
$0.5 million for a reversal of prior year unit-based compensation expense for
2008 forfeitures of unvested incentive rights and reduced incentive rights
being granted in 2008 compared to the 2007 period, offset by $0.5 million of
additional compensation expense for the incentive units voluntarily
surrendered and cancelled in the year.
Depletion, Depreciation and Accretion
Depletion, depreciation and accretion expense for 2008 was $128.9 million
($29.68/boe), compared to the $171.5 million ($29.11/boe) in 2007, which
reflects lower production volumes combined with reduced carrying costs in the
2008 period as compared to 2007.
For the year ended December 31, 2008, True has included $62.8 million for
future development costs in the depletion calculation and excluded from the
depletion calculation $31.3 million for undeveloped land and $42.5 million for
estimated salvage.
Depletion, Depreciation and Accretion Costs
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2008 2007
-------------------------------------------------------------------------
Depletion and Depreciation 126,773 169,347
Accretion 2,159 2,137
-------------------------------------------------------------------------
Total 128,932 171,484
-------------------------------------------------------------------------
Per unit ($/boe) 29.68 29.11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Special Meeting Costs
On January 15, 2007, the Trust announced its proposal to convert into an
intermediate exploration and production company (the "Reorganization").
Pursuant to the Reorganization, it was contemplated that holders of Trust
units of the Trust would receive an equal number of common shares of a newly
formed corporation that would hold the assets previously held directly or
indirectly by the Trust. The exchangeable shares were also to be exchanged for
common shares based on the conversion ratio thereof. The Reorganization was
subject to all required regulatory approvals and securityholder approval by at
least 66 2/3% of the votes cast by unitholders of the Trust and holders of the
exchangeable shares. At the Special and Annual Meeting held on March 30, 2007,
the special resolution related to the Reorganization was not approved. As a
result, the Reorganization was not completed.
The Trust incurred $3.8 million in costs for legal, financial advisory,
accounting, unitholder solicitation services, printing, mailing and other
expenses that are included as special meeting costs within the statement of
income for the year ended December 31, 2007.
Capital Expenditures
True invested $36.7 million on exploration and development activities
during 2008, compared to $87.3 million in 2007.
During the 2008 year, True had an interest in a total of 38 wells (17.1
net) drilled, which resulted in 7.1 net natural gas wells, 4.0 net light oil
wells, 0.8 net heavy oil well and 1.0 net water disposal well. 4.2 net were
dry and abandoned.
Included in the above were nine gross natural gas wells that evaluated
True land at no cost to the Company. In eight True has an overriding royalty;
in the other True has no capital cost to drill, complete and tie in, retaining
a 20% working interest from first production. True has over 377,000 net acres
of undeveloped mineral leases in Alberta, British Columbia and Saskatchewan as
of December 31, 2008. An integral component of our growth strategy is to
aggressively farmout our interest in non core areas.
Capital Expenditures
-------------------------------------------------------------------------
Years ended December 31,
($000s) 2008 2007
-------------------------------------------------------------------------
Lease acquisitions and retention 1,244 2,084
Geological and geophysical 318 4,275
Drilling and completion costs 19,008 64,638
Facilities and equipment 16,129 15,294
Other Capital(2) - 1,056
-------------------------------------------------------------------------
Exploration and development(1) 36,699 87,347
Corporate and property acquisitions 6,303 1,505
-------------------------------------------------------------------------
Total capital expenditures - cash 43,002 88,852
Property dispositions - cash (44,340) (31,808)
-------------------------------------------------------------------------
Total net capital expenditures - cash (1,338) 57,044
-------------------------------------------------------------------------
Other - non-cash(3) 3,710 (530)
-------------------------------------------------------------------------
Total net capital expenditures(1) 2,372 56,514
-------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligation
expenditures incurred during the year.
(2) Other capital for 2007 includes natural gas input costs incurred
during the initial "warm-up" phase at the Kerrobert SAGD expansion
project.
(3) Other includes non-cash adjustments for current period's asset
retirement obligations and unit based compensation capitalized. For
2007, it also includes a $(0.8 million) initial fair value adjustment
for marketable securities acquired.
The $43.0 million capital program for the year ended December 31, 2008,
was financed entirely with funds flow from operations.
During the first quarter of 2008, True was successful in completing the
divestiture of a non-core property in Northeast Alberta for net proceeds of
$5.8 million. During the second quarter of 2008, True disposed of its
Dodsland-Stranraer property located in Saskatchewan for net proceeds of $38.5
million. Total net proceeds from the sale of properties in the 2008 were $44.3
million; the net proceeds from the dispositions were used to pay down debt.
On October 1, 2008 True closed the purchase of further working interests
in the Mantario, Saskatchewan area for $4.3 million in cash after adjustments.
Based on the current economic conditions and True's operating forecast
for 2009, the Trust budgets a capital program of $15 million.
True holds an extensive land base. At December 31, 2008, True had
approximately 377,763 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 677,216 net acres in Saskatchewan,
Alberta, and British Columbia.
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.
