CALGARY, April 26 /CNW/ - (TSX-PGX.UN) Progress Energy Trust ("Progress" or
"Trust") had a very active capital program for the three months ended March 31,
2006 (the "Quarter") drilling 39 gross wells (21.0 net) with a 93 percent
success rate. New pool discoveries were made in the Deep Basin region of
northwest Alberta and the Foothills region of northeast British Columbia that
will expand the Trust's inventory of drilling locations. Daily production
averaged 18,401 barrels of oil equivalent ("boe") compared to 18,235 boe in the
first quarter of 2005 and 18,312 boe in the fourth quarter of 2005.
Progress
generated cash flow from operations of $47.6 million or $0.55 per unit, diluted
for the Quarter, a 12 percent increase compared to the first quarter of 2005.
Cash distributions declared totaled $30.8 million or $0.42 per trust unit
resulting in a payout ratio of 65 percent excluding exchangeable shares which do
not receive cash distributions.
"Our steady production profile helped to generate strong cash flow despite
weaker natural gas prices in the first quarter as compared to the fourth
quarter," said Michael Culbert, President and CEO of Progress. "Our capital
investment program included drilling over 20 net wells, acquiring additional
lands in our operating regions and participation in a large 3-D seismic program
in the Foothills of northeast British Columbia, all with a view to continuously
expand our inventory of drilling locations."
Strong netback realization
The Trust's average gas price realization for the Quarter was $8.74 per
thousand cubic feet ("mcf") after hedging, 14 percent higher than the comparable
quarter in 2005. On a before hedging basis, the Trust's gas price realization
was $8.80 per mcf. Progress' price realization achieves a premium to the prices
quoted at AECO because of the high heat content nature if its gas production.
Operating expenses averaged $5.81 per boe for the Quarter compared to $5.69
per boe in the first quarter of 2005. Per boe operating costs, transportation,
general and administrative expenses and interest expenses, key components of the
Trust's cash costs were essentially unchanged in the Quarter compared to the
same period in 2005 reflecting the Trust's ability to maintain its low cost
structure because of its concentration and quality of assets.
Maintaining financial strength
Capital investment in the Quarter was $36.0 million including $22.4 million
for drilling and completions, $8.4 million for facilities construction and $5.2
million for land and seismic data acquisition.
Progress' total debt-to-12-month trailing cash flow was 0.8 times at March
31, 2006. The Trust maintains a conservative capital structure and has used
hedging as a means to protect the Trust's cash flows supporting its capital
program and distributions.
Progress has hedged approximately 50 percent of its forecast natural gas
production to March 31, 2007. The average net floor price is $8.58 per gigajoule
("gj") for the summer of 2006 and $9.02 per gj for the winter of 2006/07.
Converting to the volumetric measure of mcf used for reporting production and
using the Trust's premium corporate heat rate achieves a net price of
approximately $10.00 per mcf, before transportation charges.
Active drilling program and consistent production profile
Daily production for the Quarter averaged 18,401 boe per day, essentially
unchanged compared to the first and fourth quarters of 2005. The production for
the Quarter included 86.4 million cubic feet per day of natural gas and
approximately 4,000 barrels of light and medium oil and natural gas liquids. The
Trust has approximately 1,000 boe per day behind pipe, which includes the
recently unitized Halfway 'C' oil pool in the Gold Creek area which is awaiting
the start-up of a waterflood recovery process.
In the Quarter, the Trust participated in 39 gross wells (21.0 net) with a 93
percent success rate. In the Deep Basin of northwest Alberta, Progress drilled
nine gross wells (6.8 net) resulting in seven gas wells and one oil well. Two
significant multi-zone exploration discoveries were made in the Deep Basin
region late in the Quarter. First production from these wells will commence in
the third quarter. The Trust currently has one rig drilling in the Gold Creek
area and anticipates running one to two drilling rigs throughout the year.
In the Foothills region of northeast British Columbia, 11 gross wells (2.8
net) were drilled targeting the pervasive Halfway sand. Progress participated in
two significant discoveries in the Foothills, each testing over 200 boe per day
from thick gas-filled reservoirs. A development program is currently being
planned for the new discoveries. Progress is participating in a deep Debolt
exploration well in the Julienne area and also participated in a 280 square
kilometer 3-D seismic shoot in the Sasquatch area of the Foothills region.
In Central Alberta, the Trust drilled 19 gross wells (11.4 net) in the
Quarter. Four of the wells targeted the Edmonton Sand play in the Gilby area
while the remaining 15 wells were CBM tests at Ewing Lake that are expected to
be brought on-stream during the second quarter.
During the Quarter, the Trust added over 7,500 net acres of prospective
exploratory acreage from Crown land sales.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") of financial results is
dated April 26, 2006 and is to be read in conjunction with the accompanying
unaudited consolidated interim financial statements and related notes for the
period ended March 31, 2006 and the audited consolidated financial statements
and related notes and MD&A of Progress Energy Trust ("Progress" or the
"Trust") for the year ended December 31, 2005. The financial data presented has
been prepared in accordance with Canadian generally accepted accounting
principles ("GAAP"). The reporting and the measurement currency is the Canadian
dollar.
Non-GAAP Measurements
Management uses cash flow from operations (before changes in non-cash working
capital) ("cash flow") to analyze operating performance and leverage. The term
distributable cash is also used to present the amount of cash that the Trust
distributes to unitholders. Neither distributable cash nor cash flow presented
have any standardized meaning prescribed by Canadian GAAP and therefore it may
not be comparable with the calculation of similar measures for other entities.
Distributable cash and cash flow as presented are not intended to represent
operating profit for the period nor should they be viewed as an alternative to
operating profit, net earnings or other measures of financial performance
calculated in accordance with Canadian GAAP. The reconciliation between net
earnings and cash flow can be found in the consolidated statements of cash flows
in the unaudited interim financial statements. Distributable cash is calculated
using cash flow less cash withheld for capital expenditures. The Trust considers
cash flow to be a key measure as it demonstrates the Trust's ability to generate
the cash necessary to pay distributions, repay debt and to fund future capital
investments. Both distributable cash and cash flow are used by research analysts
to value and compare oil and gas trusts and are frequently included in published
research when providing investment recommendations. Cash flow per unit is
calculated using the diluted weighted average number of units for the period.
All references to cash flow throughout the MD&A are based on cash flow
before changes in non-cash working capital.
Management uses certain industry benchmarks such as operating netback and
payout ratio to analyze financial and operating performance. These benchmarks as
presented do not have any standardized meaning prescribed by Canadian GAAP and
therefore may not be comparable with the calculation of similar measures for
other entities.
Forward-Looking Statements
Certain information regarding Progress set forth in this document, including
Management's assessment of the Trust's future plans and operations, contains
forward-looking statements that involve substantial known and unknown risks and
uncertainties. These forward-looking statements are subject to numerous risks
and uncertainties, certain of which are beyond the Trust's control, including
the impact of general economic conditions, industry conditions, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other producers, the lack of availability
of qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Progress' actual
results, performance or achievement could differ materially from those expressed
in, or implied by, these forward-looking statements and, accordingly, no
assurance can be given that any of the events anticipated by the forward-looking
statements will transpire or occur, or if any of them do so, what benefits that
the Trust will derive there from.
Description of Business
Progress is an open-ended, unincorporated investment trust governed by the
laws of the province of Alberta. The principal undertaking of the Trust is to
indirectly explore for, develop and hold interests in petroleum and natural gas
properties. Progress Energy Ltd., a wholly owned subsidiary of Progress, carries
on the business of the Trust and directly owns the petroleum and natural gas
properties and assets related thereto. The Trust's unitholders and exchangeable
shareholders are the sole beneficiaries of the Trust. Under the Trust Indenture,
the Trust may declare payable to unitholders all or any part of the income of
the Trust which is primarily comprised of interest earned on debt notes issued
to Progress Energy Ltd., as well as, amounts attributed to a net profits
interest agreement entered into with Progress Energy Ltd. The aggregate amounts
received by the Trust each period are based on the consolidated cash flow each
period, as adjusted on a discretionary basis, for cash withheld to fund capital
expenditures.
Progress is a Calgary based, natural gas focused, trust targeting sustainable
production and reserves per trust unit through utilization of its technical
capability and capital investment efficiencies. Primary operating regions
include the Deep Basin of northwest Alberta and the northeast British Columbia
Foothills and Fort St. John Plains regions. Trust units of Progress trade on the
Toronto Stock Exchange ("TSX") under the symbol PGX.UN. Exchangeable shares and
6.75% convertible unsecured subordinated debentures (the "Debentures") of
Progress trade on the TSX under the symbols PGE and PGX.DB respectively.
Relationship with ProEx Energy Ltd.
The Trust provides personnel and certain administrative and technical
services to ProEx Energy Ltd. ("ProEx") in connection with the management,
development, exploitation and operation of the assets of ProEx and the marketing
of its production. The Trust provides these services in accordance with the
technical services agreement ("Technical Services Agreement") entered into with
ProEx as described below.
The Trust and ProEx have joint interest in certain properties and undeveloped
land in the northeast British Columbia Foothills and Fort St. John Plains
regions. These joint interest properties are governed by standard industry
agreements and in addition the Trust has entered into a protocol arrangement
("Protocol Arrangement") with ProEx that specifies how each company will manage
the joint lands in specifically identified areas of interest. To ensure good
governance practices, both the Trust and ProEx have each created independent
committees of their Board of Directors to monitor compliance with the Technical
Services Agreement and the Protocol Arrangement.
Technical Services Agreement
The Technical Services Agreement has no set termination date and will
continue until terminated by either party with one year prior written notice to
the other party or some other date as mutually agreed. The Trust provides
services including management, development, exploitation, operations,
administrative, and marketing, as well as, information technology systems to
ProEx on an expense reimbursement basis, based on ProEx's monthly capital
activity and production levels relative to the combined capital activity and
production levels of both the Trust and ProEx.
Protocol Arrangement
The Protocol Arrangement identifies methods and processes to be followed on
both existing and new lands, joint facilities, marketing, seismic and surface
rights. The Protocol Arrangement also outlines the practices to be followed in
the event either party enters into areas outside of the identified areas of
interest.
OPERATING SUMMARY
In accordance with Canadian industry practice, production volumes, reserve
volumes and revenues are reported on a Trust interest basis (working interest
plus royalty interest), before deduction of Crown and other royalties, unless
otherwise indicated. The Trust's results of operations are dependent on
production volumes of natural gas, crude oil and natural gas liquids and the
prices received for this production. Prices for these commodities have shown
significant volatility during recent years and are determined by supply and
demand factors, including weather, general economic conditions and changes in
the Canadian/United States ("US") currency exchange rate.
In this MD&A, production and reserves information may be presented on a
"barrel of oil equivalent" or "boe" basis with six thousand cubic feet ("mcf")
of natural gas being equivalent to one barrel ("bbl") of crude oil or natural
gas liquids. Boe's may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Production
Three Months Ended
March 31
2006 2005 Change
-------------------------------------------------------------------------
Average Daily Production
Natural gas (mcf/d) 86,433 84,523 2%
Crude oil (bbls/d) 2,605 2,550 2%
Natural gas liquids (bbls/d) 1,390 1,598 (13)%
-------------------------------------------------------------------------
Total daily production (boe/d) 18,401 18,235 1%
-------------------------------------------------------------------------
Natural gas as a % of total production 78% 77%
-------------------------------------------------------------------------
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For the three months ended March 31, 2006 (the "Quarter"), Progress'
production averaged 18,401 boe per day consisting of 86,433 mcf per day of
natural gas, 2,605 bbls per day of crude oil and 1,390 bbls per day of natural
gas liquids. Production during the Quarter was consistent with the same period
in 2005 of 18,235 boe per day. The Trust's production portfolio for the
Quarter was weighted 78 percent to natural gas, 14 percent to crude oil and
8 percent to natural gas liquids.
Natural gas production of 86,433 mcf per day during the Quarter was
slightly higher than the same period in 2005 of 84,523 mcf per day. Crude oil
and natural gas liquids production for the Quarter of 3,995 bbls per day was
slightly lower than the 4,148 bbls per day produced during same period in
2005. Overall, successful drilling in the Central Alberta region and Foothills
region of northeast British Columbia exceeded natural reservoir declines and
resulted in slight production growth over the same period in 2005.
During the Quarter, Progress drilled 39 gross wells (21.0 net) with a
93 percent success rate. The Trust currently has approximately 1,000 boe per
day behind pipe which includes the recently unitized Halfway 'C' oil pool in
the Gold Creek area which is awaiting the start-up of a waterflood recovery
process.
Management anticipates production to average between 18,700 to 19,000 boe
per day in 2006. This estimate takes into account natural reservoir declines
and forecasted capital expenditures of $100 million.
Production by Region
Three Months Ended
March 31
2006 2005 Change
-------------------------------------------------------------------------
Average Daily Production (boe/d)
Foothills 3,712 3,195 16%
Fort St. John Plains 2,234 2,398 (7)%
Other 422 561 (25)%
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Total British Columbia 6,368 6,154 3%
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Deep Basin 9,037 9,251 (2)%
Central Alberta 1,704 1,590 7%
Other 912 874 4%
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Total Alberta 11,653 11,715 (1)%
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Saskatchewan 380 366 4%
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Total daily production 18,401 18,235 1%
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Pricing and Risk Management
Natural Gas Markets
Progress' realized natural gas price for the Quarter was $8.80 per mcf,
before the impact of hedging, compared to the AECO daily index average of
$7.13 per gigajoule ("gj"). The higher realization reflects the higher heat
content of Progress' natural gas stream. Including the impact of hedging, the
Trust realized an average of $8.74 per mcf.
The first three months of 2006 marked some of the warmest winter weather
on record in North America causing demand for natural gas to be down from
historic winter levels. The result is that working gas in storage in the US
and Canada are at record levels at the end of the winter withdrawal season on
March 31. US natural gas in storage stands at 1.7 trillion cubic feet or
36 percent above 2005 levels and 63 percent above the five-year average. In
Canada, winter-ending storage levels were 68 percent above 2005 levels and
59 percent above the five-year average.
North American natural gas markets have historically shown the ability to
self correct the supply-demand imbalance over time although prices are
expected to remain volatile in the coming months. Heading into the summer, the
price for alternative fuel sources such as residual fuel oil and distillates
will provide a relative floor for natural gas although this floor may be
breeched at times in the absence of any air conditioning induced demand.
Weather will again play an important part in the natural gas supply-demand
balance through the summer as forecasters consider the potential for elevated
hurricane activity which may disrupt gas production from the Gulf of Mexico
from time to time. At the time of writing, approximately 1.4 billion cubic
feet per day or approximately 14 percent of Gulf of Mexico gas production
remains shut-in from last summers' storms.
In the longer term, weaker gas prices, if sustained, will also have the
likely impact of reducing rig activity across North America and ultimately gas
completions. This would further exacerbate the challenges for production in
North America which is running harder and faster to offset an already steep
annual decline in natural gas production.
Oil Markets
Progress' first quarter realized prices for its liquids streams were
$64.45 per bbl for crude oil and $62.86 per bbl for natural gas liquids.
Crude oil prices continue to strengthen as numerous supply-side factors
worldwide outweigh the markets concerns about ample inventories of crude oil
and refined products in North America. The US has historically been considered
the bellwether for oil and product inventories but supply concerns are
assessed on a global basis given the relative growth of non-OECD countries
such as China. Several above ground forces including a shortage of oilfield
equipment and personnel and political issues created by rising nationalism
(i.e. Venezuela) will likely remain in place for some time to come and will
only add further volatility.
The global oil demand picture is ever evolving with a steady rotation
toward transportation fuels and non-OECD-led growth. These shifting tides are
likely to underpin the demand for light sweet crude streams like WTI and weigh
upon heavier grades of crude. Progress' crude oil production is made up
predominately of light crude and does not include any heavy oil.
Commodity Prices
Three Months Ended
March 31
2006 2005 Change
-------------------------------------------------------------------------
Average Benchmark Prices
Natural gas - AECO (daily) ($/gj) 7.13 6.53 9%
Natural gas - AECO (monthly) ($/gj) 8.79 6.34 39%
Crude oil - WTI (US$/bbl) 63.48 49.84 27%
Crude oil - Edmonton par price (Cdn$/bbl) 69.00 61.49 12%
Exchange rate (Cdn$/US$) 1.1545 1.2270 (6)%
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Average Realized Prices
Natural gas - before hedging ($/mcf) 8.80 7.31 20%
Hedge settlements ($/mcf) (0.08) 0.39 (121)%
Amortization of hedge premiums ($/mcf) - (0.03) 100%
Amortization of commodity sales contract
($/mcf)(1) 0.02 0.02 -
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Natural gas - after hedging ($/mcf) 8.74 7.69 14%
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Crude oil ($/bbl) 64.45 59.44 8%
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Natural gas liquids ($/bbl) 62.86 47.82 31%
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(1) Amortization of physical natural gas sales contract acquired in
conjunction with the acquisition of Campion Resources Ltd. on June 3,
2002. Contract expires in 2008.
Risk Management
The Trust has entered into several natural gas financial contracts for
the purpose of protecting its cash flow from the volatility of natural gas
prices. For the Quarter, the Trust's natural gas price risk management program
had a net loss of $0.6 million (2005 - $2.8 million net gain), which is
included in petroleum and natural gas revenue on the statements of earnings.
The Trust's hedging activities are conducted pursuant to the Trust's Risk
Management Policy approved by the Board of Directors. Progress uses financial
derivative instruments designed to establish a minimum floor price while
retaining exposure to upside price movements. The Risk Management Policy has
the following objectives:
- To reduce risk exposure to budgeted annual cash flow projections
resulting from uncertainty or changes in commodity prices, interest
rates or foreign exchange.
- To provide greater certainty and stability to monthly distributions.
- To limit the permissible structures to ensure hedging effectiveness.
- To limit hedging up to a maximum of 50 percent of budgeted production
before royalties.
- To limit hedging activity to counter-parties that provide sufficient
collateral in support of payment or have investment grade credit
ratings.
Progress' commodity risk management positions are fully described in
Note 10 in the unaudited interim consolidated financial statements attached.
The Trust currently has natural gas financial instruments in place, which
consist of swap and call spread contracts, for the following production
volumes:
Contract Natural
Gas Volumes % of Estimated
('000 gj/d) Natural Gas Production
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Second quarter of 2006 40.0 50
Third quarter of 2006 40.0 50
Fourth quarter of 2006 40.0 50
First quarter of 2007 40.0 50
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Revenue
For the Quarter, petroleum and natural gas revenue increased 15 percent
to $91.0 million from $79.0 million for the same period in 2005 due to
increased commodity prices. Production revenue before hedging for the Quarter
consisted of $68.4 million from natural gas sales, $15.1 million from crude
oil sales and $7.9 million from the sale of natural gas liquids.
Three Months Ended
March 31
($ thousands) 2006 2005 Change
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Natural gas sales 68,445 55,641 23%
Crude oil sales 15,112 13,639 11%
Natural gas liquids sales 7,864 6,879 14%
Hedge settlements (609) 2,930 (120)%
Amortization of hedge premiums - (250) -
Amortization of commodity sales contract(1) 147 168 (13)%
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Petroleum and natural gas revenue 90,959 79,007 15%
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(1) Amortization of physical natural gas sales contract acquired in
conjunction with the acquisition of Campion Resources Ltd. on June 3,
2002. Contract expires in 2008.
Crude
Natural Oil
($ thousands) Gas & NGLs Total
-------------------------------------------------------------------------
Q1 2005 Petroleum and natural gas revenue 58,489 20,518 79,007
Price variance 8,172 3,215 11,387
Production variance 1,322 (757) 565
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Q1 2006 Petroleum and natural gas revenue 67,983 22,976 90,959
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Royalties
Royalty expense consists of royalties paid to provincial governments,
freehold landowners and overriding royalty owners, net of credits received
through the Alberta royalty tax credit program. For the Quarter, royalties
increased 27 percent to $24.6 million from $19.3 million for the same period
in 2005. The Trust's average royalty rate (after removing the effects of
hedging charges) for the Quarter was 26.9 percent compared to 25.4 percent in
2005. The higher royalty rate in 2006 is the result of higher commodity
prices.
Management anticipates, based on current commodity prices, the average
royalty rate for the remainder of 2006, before the impact of hedging will be
approximately 26.0 percent of petroleum and natural gas revenue.
Operating Expenses
Operating expenses during the Quarter were $9.6 million, consistent with
the same period in 2005 of $9.3 million. On a boe basis, operating expenses
for the Quarter increased two percent to $5.81 from $5.69 in the same period
in 2005. Progress has experienced increased costs for well servicing,
insurance, workovers and well maintenance. Through increased operating
efficiencies and the addition of low operating cost per boe production, the
Trust has been able to offset these increases and keep operating costs per boe
flat quarter over quarter.
Management anticipates operating expense for the remainder of 2006 to be
between $5.50 to $6.00 per boe.
Transportation Expenses
Transportation expenses were $3.2 million for the Quarter, consistent
with the same period in 2005 of $3.1 million. On a boe basis, transportation
expenses during the Quarter of $1.91 were consistent with the same period in
2005 of $1.89. In British Columbia, there is an infrastructure owned by Duke
Energy that enables gas producers to avoid facility construction in exchange
for regulated gathering, processing and transmission fees. This all-in charge
is included in transportation expenses.
Operating Netbacks
Although many wells produce both crude oil and natural gas, a well is
categorized as a natural gas well or an oil well based upon the higher
proportion of natural gas or crude oil production. The following table
summarizes the operating netbacks for natural gas and oil properties for the
Quarter compared to the same period in 2005:
Three Months Ended
March 31
2006 2005
-------------------------------------------------------------------------
Natural Gas Properties ($/mcf)
Sales price - before hedging 8.99 7.46
Hedging settlements (0.07) 0.36
Amortization of hedge premiums - (0.03)
Amortization of commodity sales contract 0.02 0.02
Royalties (2.51) (2.19)
Operating expenses (0.87) (0.79)
Transportation expenses (0.31) (0.32)
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Operating netback - natural gas properties 5.25 4.51
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Oil Properties ($/bbl)
Sales Price - before hedging 62.41 54.88
Royalties (13.81) (4.70)
Operating expenses (9.20) (10.53)
Transportation expenses (2.06) (1.86)
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Operating netback - oil properties 37.34 37.79
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All Properties ($/boe)
Sales Price - before hedging 55.20 46.41
Hedging settlements (0.37) 1.78
Amortization of hedge premiums - (0.15)
Amortization of commodity sales contract 0.09 0.10
Royalties (14.87) (11.78)
Operating expenses (5.81) (5.69)
Transportation expenses (1.91) (1.89)
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Operating netback - all properties 32.33 28.78
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General and Administrative Expenses
For the Quarter, general and administrative expenses net of overhead
recoveries, ("G&A") decreased 11 percent to $1.8 million ($1.08 per boe)
compared to $2.0 million ($1.22 per boe) for the same period in 2005. The
decrease in G&A for the Quarter is due to higher technical service fees from
ProEx as a result of its increased production.
In accordance with the Technical Services Agreement with ProEx, the Trust
provides personnel and certain administrative and technical services in
connection with the management, development, exploitation and operation of the
assets of ProEx and the marketing of its production. The Trust provides these
services to ProEx on an expense reimbursement basis, based on ProEx's monthly
capital activity and production levels relative to the combined capital
activity and production levels of both the Trust and ProEx. Total expenses
reimbursed by ProEx for the Quarter were $1.1 million compared to $0.6 million
for the same period in 2005.
The Trust capitalized approximately $0.3 million of G&A during the
Quarter compared to $0.4 million for the same period in 2005. The majority of
these costs represent geological and geophysical salaries.
Management anticipates G&A expenses to average in the range of $1.00 to
$1.20 per boe for the remainder of 2006.
Unit Based Compensation Expenses
For the Quarter, unit based compensation expenses relating to the
performance unit incentive plan increased 97 percent to $1.0 million
($0.61 per boe) compared to $0.5 million ($0.31 per boe) for the same period
in 2005. The increase is due to the performance units granted effective
July 2, 2005. The Progress performance unit plan provides for employees and
directors to be granted performance units which vest at the end of a three
year performance period at which time they will be converted to trust units,
or the cash equivalent, and include the accumulated distributions over the
three year period. The actual number of trust units paid is dependent upon a
performance factor that is determined based on the Trust's performance
relative to its peers and ranges from 0.5 to 1.5 times the initial grant.
Payment may be in the form of cash or trust units, at the Trust's option.
Management anticipates, at the end of the performance period, accumulated
distributions will be paid in cash and trust units will be paid from treasury.
Progress' performance unit incentive plan is fully described in note 8 in the
unaudited consolidated interim financial statements attached.
Management anticipates unit based compensation expenses will average
$0.75 per boe in 2006 as an additional layer of performance units are expected
to be granted in the third quarter.
Interest and Financing Expenses
Interest and financing expenses during the Quarter increased 15 percent
to $2.4 million compared to $2.1 million for the same period in 2005. The
increase is primarily due to higher average debt levels and a full quarter of
Debenture interest in 2006 compared to 2005. For a further discussion of the
Debentures see the "Liquidity and Capital Resources" section below.
Three Months Ended
March 31
($ thousands) 2006 2005
-------------------------------------------------------------------------
Interest on bank debt 922 757
Interest on Debentures 1,191 1,054
Amortization of Debenture issue costs 138 130
Accretion on debt portion of Debentures(1) 145 139
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Total interest and financing expense 2,396 2,080
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(1) Under Canadian GAAP, the fair value of the conversion feature of the
Debentures is classified as equity and the remainder is classified as
debt. Over the term of the Debentures, the debt portion will accrete
up to the principal balance at maturity with the charge going to
interest and financing expenses.
Depletion, Depreciation and Accretion
For the Quarter, depletion and depreciation of property, plant and
equipment and the accretion of the asset retirement obligations ("DD&A")
increased three percent to $23.6 million from $23.1 million for the same
period in 2005. The increase is due to a higher depletable base in 2006 as a
result of capital spending and the accounting for exchangeable shares, whereby
the conversion of exchangeable shares results in a charge to property, plant
and equipment. On a boe basis, DD&A for the Quarter was $14.27 compared to
$14.05 for the same period in 2005.
Management expects depletion, depreciation and accretion per boe for the
remainder of 2006 to be approximately $14.50 per boe.
Income and Capital Taxes
Capital taxes for the Quarter decreased 38 percent to $0.3 million
compared to $0.5 million for the same period in 2005. The decrease is due to a
lower large corporation tax rate as the tax continues to be phased out.
The provision for future income taxes for the Quarter was a recovery of
$0.9 million compared to a recovery of $2.4 million in same period in 2005.
The lower recovery for 2006 is the result of higher earnings for the Quarter
compared to the same period in 2005 due to higher commodity prices. The Trust
is a taxable entity under the Income Tax Act (Canada) and is taxable only on
income that is not distributed or distributable to the unitholders. It is
expected the Trust will not incur any cash income taxes in the future and as
such the future tax liability recorded on the balance sheet will recover
through future net earnings.
Non-Controlling Interest - Exchangeable Shares
The exchangeable shares of the Trust's subsidiary trade on the TSX,
thereby allowing holders of the exchangeable shares to dispose of them without
having to exchange them for trust units and consequently, they must be
classified as non-controlling interest outside of unitholders' equity. The net
earnings attributable to the exchangeable shares is charged to the
consolidated statement of earnings as non-controlling interest with a
corresponding increase to non-controlling interest on the consolidated balance
sheet.
Three Months Ended March 31
2006 2005
-------------------------------------------------------------------------
($ thousands,
except unit amounts) Number Amount Number Amount
-------------------------------------------------------------------------
Exchangeable Shares
Balance,
beginning of period 11,388,751 127,205 14,533,506 141,060
Exchanged for trust units (1,242,992) (14,145) (1,630,768) (16,001)
Non-controlling
interest expense 3,921 3,940
-------------------------------------------------------------------------
Balance, end of period 10,145,759 116,981 12,902,738 128,999
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The charge to net earnings of $3.9 million for 2006 and 2005 represents
the net earnings attributable to the exchangeable shares over the period.
Net Earnings and Cash Flow
Net earnings increased 22 percent to $21.4 million for the Quarter
compared to $17.5 million during the same period in 2005. The increase was due
to increased commodity prices. Basic and diluted net earnings for the Quarter
were $0.29 per unit compared to $0.26 per unit during the same period in 2005.
Cash flow increased 12 percent to $47.6 million for the Quarter compared
to $42.5 million during the same period in 2005 due to higher commodity
prices. Diluted cash flow for the Quarter was $0.55 per unit compared to
$0.51 per unit during the same period in 2005.
Quarterly Financial Summary(1)(2)
Three Months Ended
-----------------------------------
($ thousands, except Mar 31 Dec 31 Sept 30 June 30
per unit amounts) 2006 2005 2005 2005
-------------------------------------------------------------------------
Petroleum and natural gas revenue 90,959 114,167 93,372 83,222
-------------------------------------------------------------------------
Cash flow 47,637 65,785 53,215 44,466
Per unit diluted 0.55 0.77 0.63 0.53
-------------------------------------------------------------------------
Net earnings 21,383 29,398 25,159 16,840
Per unit basic 0.29 0.41 0.36 0.25
Per unit diluted 0.29 0.40 0.36 0.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three Months Ended
-----------------------------------
($ thousands, except Mar 31 Dec 31 Sept 30 Jun 30
per unit amounts) 2005 2004 2004 2004
-------------------------------------------------------------------------
Petroleum and natural gas revenue 79,007 76,767 68,299 38,811
-------------------------------------------------------------------------
Cash flow 42,511 41,344 36,355 17,833
Per unit diluted 0.51 0.50 0.45 0.49
-------------------------------------------------------------------------
Net earnings 17,526 18,196 15,324 4,464
Per unit basic 0.26 0.28 0.24 0.13
Per unit diluted 0.26 0.28 0.24 0.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The above amounts have been restated for the change in accounting
policy related to non-controlling interest.
(2) Quarterly petroleum and natural gas revenue and cash flow increased
in the first quarter of 2004 primarily due to increased production
due to successful drilling in British Columbia. For the third and
fourth quarters of 2004 and the first and second quarters of 2005
petroleum and natural gas revenue and cash flow increased primarily
due to the Cequel acquisition and successful drilling in the British
Columbia core regions, partially offset by the transfer of assets to
ProEx as part of the Arrangement. Petroleum and natural gas revenue
and cash flow for the third and fourth quarters of 2005 and
thereafter increased due to strengthening commodity prices. Petroleum
and natural gas revenue and cash flow for the first quarter of 2006
decreased as a result of lower natural gas prices.
Distributable Cash and Distributions
Management monitors the Trust's distribution payout policy with respect
to forecasted net cash flow, debt levels and capital expenditures. Progress
expects to distribute approximately 60 to 70 percent of its annual cash flow
to unitholders and retain the remaining cash flow for capital expenditures and
debt repayment. Exchangeable shares are convertible into trust units of the
Trust based on the exchange ratio, which is adjusted monthly to reflect that
distributions are not paid on the exchangeable shares and cash flow related to
the exchangeable shares is retained by the Trust for additional capital
expenditures or debt repayment. The key drivers of Progress' cash flow, as is
generally the case with other energy trusts, are commodity prices and
production. Since the Trust's production is heavily weighted to natural gas
(78 percent in the Quarter), natural gas prices have a significant effect on
its cash flow.
Distributable cash is not a measure under Canadian GAAP and there is no
standard measure of distributable cash. Distributable cash, as presented, may
not be comparable to similar measures presented by other trusts. Progress'
initial cash distribution declared was $0.14 per trust unit for the month of
July 2004. The Trust has maintained this distribution to date.
Three Months Ended
March 31
($ thousands, except per unit amounts) 2006
-------------------------------------------------------------------------
Cash flow 47,637
Cash withheld to fund capital expenditures (16,801)
-------------------------------------------------------------------------
Cash distributions declared 30,836
Accumulated cash distributions, beginning of period 172,165
-------------------------------------------------------------------------
Accumulated cash distributions, end of period 203,001
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash distributions per unit(1) 0.42
Accumulated cash distributions per unit, beginning of period 2.52
-------------------------------------------------------------------------
Accumulated cash distributions per unit, end of period 2.94
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash distributions per trust unit reflect the sum of the per trust
unit amounts paid and declared to unitholders.
Capital Expenditures
During the Quarter, the Trust invested $36.0 million in capital
expenditures compared to $34.4 million in the same period in 2005.
Three Months Ended
March 31
($ thousands) 2006 2005
-------------------------------------------------------------------------
Land acquisitions and retention 2,840 1,727
Geological and geophysical 2,002 1,223
Drilling and completions 22,412 20,828
Equipping and facilities 8,397 9,246
Net property acquisitions (dispositions) 298 964
Corporate assets 36 392
-------------------------------------------------------------------------
Total capital expenditures 35,985 34,380
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the Quarter, Progress drilled 39 gross wells (21.0 net) with a
93 percent success rate. Nine gross wells (6.8 net) were drilled in the Deep
Basin region of northwest Alberta, 11 wells (2.8 net) in northeast British
Columbia, four wells (3.9 net) into the Edmonton Sand play in Central Alberta
and 15 CBM wells (7.5 net) also in Central Alberta.
The Trust's remaining 2006 capital investment program will continue to be
directed to the three focus regions of the Deep Basin in northwest Alberta and
the Fort St. John Plains and Foothills of northeast British Columbia. The
total 2006 capital program is estimated to be approximately $100.0 million
with 55 to 65 net wells expected to be drilled for the year. The capital
program is expected to be split approximately 65 percent to drilling and
completions, 10 percent to major facilities and 25 percent to land and seismic
expenditures. The Trust does not set a budget for property acquisitions.
Liquidity and Capital Resources
March 31 December 31
($ thousands, except per unit amounts) 2006 2005
-------------------------------------------------------------------------
Working capital deficiency 18,382 22,873
Bank debt 95,000 71,326
Convertible debentures 58,724 79,381
-------------------------------------------------------------------------
Total debt 172,106 173,580
-------------------------------------------------------------------------
Units outstanding and issuable
for exchangeable shares (thousands) 86,624 84,784
Market price per unit at end of period 17.45 17.17
-------------------------------------------------------------------------
Market value of trust units
and exchangeable shares 1,511,589 1,455,741
-------------------------------------------------------------------------
Cash flow (12 month trailing) 211,103 205,977
Total debt to cash flow ratio 0.82 0.84
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At March 31, 2006 the Trust had $95.0 million outstanding on its credit
facilities, $58.7 million for the debt portion of the Debentures and a working
capital deficiency of $18.4 million, totaling $172.1 million of total debt.
The Trust currently has a $200 million extendible revolving term credit
facility and a $15 million working capital credit facility with a syndicate of
banks. The facilities are available on a revolving basis for a period of at
least 364 days until May 30, 2006, and such initial term out date may be
extended for further 364 day periods at the request of the Trust, subject to
approval by the banks. Following the term out date, the facilities will be
available on a non-revolving basis for a one year term, at which time the
facilities would be due and payable. The credit facilities are secured by a
$500 million fixed and floating charge debenture on the assets of the Trust
and by a guarantee and subordination provided by Progress Energy Ltd. in
respect of the Trust's obligations. The $215 million borrowing base is subject
to semi-annual review by the banks.
Bank debt increased from $71.3 million as at December 31, 2005 to
$95.0 million as at March 31, 2006 due to capital spending in the Quarter. The
working capital deficiency of $18.4 million at March 31, 2006 is lower than
the December 31, 2005 deficiency of $22.9 million, primarily due to reduced
accounts payable balance partially offset by a reduction in accounts
receivable due to lower natural gas prices.
At March 31, 2006 the Trust had outstanding $63.5 million principal
amount of 6.75 percent convertible unsecured subordinated debentures, the debt
portion of which, net of debenture issue costs was $58.7 million. The
Debentures pay interest semi-annually and are convertible at the option of the
holder at any time into fully paid trust units at a conversion price of $15.00
per trust unit. The Debentures mature on June 30, 2010 at which time they are
due and payable.
The Debentures are classified as debt net of the fair value of the
conversion feature which has been classified as part of unitholders' equity
and net of issue costs. At March 31, 2006 the debt portion was $58.7 million
and the equity portion was $3.1 million. Issue costs are amortized over the
term of the Debentures, and the debt portion will accrete up to the principal
balance at maturity. The accretion, amortization of issue costs and the
interest paid are expensed within interest and financing expense on the
consolidated statements of earnings.
Outstanding as at April 25, 2006 were 74.5 million trust units,
10.1 million exchangeable shares and $61.4 million convertible debentures
convertible into 4.1 million trust units.
The Trust's investing activities in the Quarter primarily consists of
expenditures on its capital program. Management anticipates that the Trust
will continue to have adequate liquidity to fund future working capital and
forecasted capital expenditures during 2006 through a combination of cash flow
and debt. Cash flow used to finance these commitments may reduce the amount of
cash distributions paid to unitholders.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by the Trust is accumulated and
communicated to the Trust's Management, as appropriate, to allow timely
decisions regarding required disclosures. The Trust's Chief Executive Officer
and Chief Financial Officer have concluded, based on their evaluation as of
the end of the period covered by the interim filings that the Trust's
disclosure controls and procedures are effective to provide reasonable
assurance that material information related to the issuer, is made known to
them by others within the Trust. It should be noted that while the Trust's
Chief Executive Officer and Chief Financial Officer believe that the Trust's
disclosure controls and procedures provide a reasonable level of assurance
that they are effective, they do not expect that the disclosure controls and
procedures or internal control over financial reporting will prevent all
errors and fraud. A control system, no matter how well conceived or operated,
can provide only reasonable, not absolute, assurance that the objective of the
control system is met.
Additional Information
Additional information regarding the Trust and its business and
operations, including the annual information form ("AIF") is available on the
Trust's company profiles at www.sedar.com. Copies of the AIF can also be
obtained by contacting the Trust at Progress Energy Trust 1400, 440 - 2nd
Avenue S.W., Calgary, Alberta, Canada T2P 5E9 or by e-mail at
ir(at)progressenergy.com. This information is also accessible on the Trust's
web site at www.progressenergy.com.
OUTLOOK
Progress will continue to pursue a disciplined approach to long term
sustainability on a per unit basis. Our technical approach and cost control
will be primary contributors to sustained value creation for unitholders.
Internally generated opportunities will be drilled at a more modest pace than
when we were an aggressive growth company. Our inventory of drilling locations
currently supports approximately 2 years of activity for Progress while our
over 500,000 net acres of undeveloped land provides the opportunity for our
technical team to create incremental value.
In creating our Trust, we ensured that we would have access to strong
technical and financial staff by having all employees invest in Progress. This
creates strong alignment with our unitholders and ensures that we have the
professionals to execute our business plan. Employees, Management and
Directors hold a 13 percent direct ownership interest in our Trust.
On behalf of the Board of Directors,
(Signed) "Michael R. Culbert"
-----------------------------
Michael R. Culbert
President & CEO
April 26, 2006
PROGRESS ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
March 31 December 31
($ thousands) 2006 2005
-------------------------------------------------------------------------
ASSETS (Unaudited)
Current
Cash and short-term investments 3,554 -
Accounts receivable 34,407 45,870
Prepaid expenses and deposits 4,991 5,144
-------------------------------------------------------------------------
42,952 51,014
Property, plant and equipment (Note 3) 712,084 687,316
Goodwill 414,655 414,655
-------------------------------------------------------------------------
1,169,691 1,152,985
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities 45,995 58,904
Cash distributions payable 10,404 9,982
Current income taxes payable 4,935 5,001
-------------------------------------------------------------------------
61,334 73,887
Bank debt (Note 4) 95,000 71,326
Convertible debentures (Note 5) 58,724 79,381
Commodity sales contract (Note 10) 1,299 1,446
Asset retirement obligations (Note 6) 21,824 20,906
Future income taxes 126,576 124,186
-------------------------------------------------------------------------
364,757 371,132
NON-CONTROLLING INTEREST
Exchangeable shares (Notes 2 and 7) 116,981 127,205
UNITHOLDERS' EQUITY
Unitholders' capital (Note 8) 723,974 681,263
Convertible debentures (Note 5) 3,137 4,261
Contributed surplus (Note 8) 4,701 3,530
Deficit (43,859) (34,406)
-------------------------------------------------------------------------
687,953 654,648
-------------------------------------------------------------------------
1,169,691 1,152,985
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
PROGRESS ENERGY TRUST
CONSOLIDATED STATEMENTS OF EARNINGS AND DEFICIT
(Unaudited)
Three Months Ended
March 31
($ thousands, except per unit amounts) 2006 2005
-------------------------------------------------------------------------
(Restated
Note 2)
REVENUE
Petroleum and natural gas 90,959 79,007
Royalties (24,619) (19,337)
-------------------------------------------------------------------------
66,340 59,670
-------------------------------------------------------------------------
EXPENSES
Operating 9,628 9,330
Transportation 3,161 3,095
General and administrative 1,789 2,010
Unit based compensation 1,007 512
Interest and financing 2,396 2,080
Depletion, depreciation and accretion 23,643 23,065
-------------------------------------------------------------------------
41,623 40,092
-------------------------------------------------------------------------
Earnings before taxes and non-controlling interest 24,717 19,578
-------------------------------------------------------------------------
TAXES
Capital taxes 339 543
Future income taxes (926) (2,431)
-------------------------------------------------------------------------
(587) (1,888)
-------------------------------------------------------------------------
Net earnings before non-controlling interest 25,304 21,466
Non-controlling interest -
exchangeable shares (Note 7) (3,921) (3,940)
-------------------------------------------------------------------------
NET EARNINGS 21,383 17,526
Deficit, beginning of period (34,406) 1,476
Retroactive application of change
in accounting policy (Note 2) - (8,346)
-------------------------------------------------------------------------
Deficit, beginning of period, as restated (34,406) (6,870)
Distributions (30,836) (28,574)
-------------------------------------------------------------------------
Deficit, end of period (43,859) (17,918)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS PER UNIT (Note 8)
Basic $0.29 $0.26
Diluted $0.29 $0.26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
PROGRESS ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31
($ thousands) 2006 2005
-------------------------------------------------------------------------
(Restated
Note 2)
OPERATING ACTIVITIES
Net earnings 21,383 17,526
Depletion, depreciation and accretion 23,643 23,065
Non-controlling interest -
exchangeable shares (Note 7) 3,921 3,940
Convertible debentures accretion (Note 5) 145 139
Amortization of convertible
debenture issue costs (Note 5) 138 130
Amortization of commodity sales contract (147) (168)
Unit based compensation expense (Note 8) 1,007 512
Asset retirement expenditures (Note 6) (1,527) (202)
Future income taxes (926) (2,431)
-------------------------------------------------------------------------
47,637 42,511
Changes in non-cash working capital (Note 9) 2,698 1,716
-------------------------------------------------------------------------
50,335 44,227
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Increase (decrease) in bank debt 23,674 (78,026)
Issue of 6.75 % convertible debentures (Note 5) - 100,000
Convertible debenture issue costs (Note 5) - (4,549)
Cash distributions (30,414) (28,328)
Changes in non-cash working capital (Note 9) - -
-------------------------------------------------------------------------
(6,740) (10,903)
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (35,984) (34,380)
Changes in non-cash working capital (Note 9) (4,057) 1,056
-------------------------------------------------------------------------
(40,041) (33,324)
-------------------------------------------------------------------------
CHANGE IN CASH AND SHORT-TERM INVESTMENTS 3,554 -
Cash and short-term investments, beginning of period - -
-------------------------------------------------------------------------
CASH AND SHORT-TERM INVESTMENTS, END OF PERIOD 3,554 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
PROGRESS ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) (tabular amounts are in $ thousands except for trust units
and per trust unit amounts)
Progress Energy Trust ("Progress" or the "Trust") is an open-ended,
unincorporated investment trust governed by the laws of the province of
Alberta. The principal undertaking 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 royalty interests
in petroleum and natural gas properties. Progress Energy Ltd. carries on
the business of the Trust and directly owns the petroleum and natural gas
properties and assets related thereto. The Trust owns, directly and
indirectly, 100 percent of the common shares (excluding the exchangeable
shares - see notes 2 and 7) of Progress Energy Ltd. The activities of
Progress Energy Ltd. are financed through interest bearing notes from the
Trust and third party debt. The convertible debentures are direct
obligations of the Trust. Under the Trust Indenture, the Trust may
declare payable to unitholders all or any part of the income of the
Trust, which is primarily comprised of interest earned on debt notes
issued to Progress Energy Ltd., as well as, amounts attributed to a net
profits interest ("NPI") agreement entered into with Progress Energy Ltd.
The aggregate amounts received by the Trust each period are based on the
consolidated cash flow from operations before changes in non-cash working
capital each period, as adjusted on a discretionary basis, for cash
withheld to fund capital expenditures.
Pursuant to the terms of the NPI agreement, the Trust is entitled to a
payment from Progress Energy Ltd. each month equal to the amount by which
99% of the gross proceeds from the sale of production exceed 99% of
certain deductible expenditures (as defined). Under the terms of the NPI
agreement, deductible expenditures may include amounts, determined on a
discretionary basis, to fund capital expenditures, to repay third party
debt and to provide for working capital required to carry out the
operations of Progress Energy Ltd.
Relationship with ProEx Energy Ltd.
A technical services agreement ("Technical Service Agreement") is
currently in place between the Trust and ProEx Energy Ltd. ("ProEx")
whereby the Trust provides personnel and certain administrative and
technical services in connection with the management, development,
exploitation and operation of the assets of ProEx and the marketing of
its production. ProEx has granted performance shares to the employees of
Progress as service providers. The Trust provides these services to ProEx
on an expense reimbursement basis, based on ProEx's monthly capital
activity and production levels relative to the combined capital activity
and production levels of both the Trust and ProEx. Total expense
reimbursed by ProEx for the three months ended March 31, 2006 was
$1.1 million (2005 - $0.6 million).
As at March 31, 2006, accounts payable included $0.2 million (2005 -
$6.7 million) payable to ProEx which includes standard joint venture
amounts including revenue. These amounts were paid subsequent to
March 31, 2006.
1. SUMMARY OF ACCOUNTING POLICIES
The interim consolidated financial statements of the Trust have been
prepared following the same accounting policies and methods of
computation as the consolidated financial statements of the Trust for
the year ended December 31, 2005. The disclosures provided below are
incremental to those included with the annual consolidated financial
statements and certain disclosures, which are normally required to be
included in the notes to the annual consolidated financial
statements, have been condensed or omitted. These interim
consolidated financial statements should be read in conjunction with
the consolidated financial statements and notes thereto in the
Trust's annual report for the year ended December 31, 2005.
Progress is involved in the exploration, development and production
of petroleum and natural gas in British Columbia, Alberta and
Saskatchewan. The consolidated financial statements include the
accounts of the Trust and its wholly owned subsidiary. The
consolidated financial statements are stated in Canadian dollars and
have been prepared in accordance with Canadian generally accepted
accounting principles ("GAAP").
The preparation of financial statements in conformity with Canadian
GAAP requires Management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial
statements and reported amounts of revenues and expenses during the
period. Actual results could differ from those estimates.
2. CHANGE IN ACCOUNTING POLICY
Exchangeable Securities - Non-Controlling Interest
On March 8, 2005 the accounting abstract "Exchangeable Securities
Issued by Subsidiaries of Income Trusts" was amended effective for
financial statements issued on or after June 30, 2005. Under the
amended abstract, exchangeable shares are presented as equity of the
Trust only if the exchangeable shares are entitled to receive
distributions of earnings economically equivalent to distributions
received by units of the trust and the holders of exchangeable shares
can only dispose of them by exchanging them for trust units. The
exchangeable shares of the Trust's subsidiary trade on the Toronto
Stock Exchange, thereby allowing holders of the exchangeable shares
to dispose of them without having to exchange them for trust units
and consequently, they must be classified as non-controlling interest
outside of unitholders' equity.
In accordance with the transitional provisions of the abstract, the
Trust has retroactively restated prior periods dating back to July 2,
2004, the date of the Plan of Arrangement under which the Trust was
created. Each redemption of exchangeable shares held by previous
Progress Energy Ltd. shareholders are accounted for as a step-
purchase resulting in an increase to property, plant and equipment,
an increase to unitholders' capital and an increase in the Trust's
future income tax liability. Cash flow was not impacted by this
change. The non-controlling interest activity for the three months
ended March 31, 2006 and 2005 is disclosed in note 7. The effect of
the adoption on the previously reported amounts for the three months
ended March 31, 2005 is presented below as increases (decreases):
Statement of Earnings
Three Months Ended
March 31, 2005
---------------------------------------------------------------------
Depletion, depreciation and accretion 804
Future income taxes (277)
Non-controlling interest 3,940
Net earnings (4,467)
Net earnings per unit
Basic (0.01)
Diluted (0.01)
---------------------------------------------------------------------
---------------------------------------------------------------------
3. PROPERTY, PLANT AND EQUIPMENT
March 31 December 31
2006 2005
---------------------------------------------------------------------
Property, plant and equipment 903,347 865,173
Conversion of exchangeable shares 42,371 32,553
Accumulated depletion and depreciation (233,634) (210,410)
---------------------------------------------------------------------
Property, plant and equipment, net 712,084 687,316
---------------------------------------------------------------------
---------------------------------------------------------------------
As described in note 2, the redemption of exchangeable shares held by
previous Progress Energy Ltd. shareholders are accounted for as a
step-purchase. Consequently a charge of $9.8 million was made to
property, plant and equipment for the three months ended March 31,
2006.
The calculation of 2005 depletion and depreciation expense included
an estimated $19.4 million for future development costs associated
with proved undeveloped reserves and excluded $24.0 million for the
estimated future net realizable value of production equipment and
facilities and $65.7 million for the estimated value of unproven
properties. Depletion and depreciation expense for the three months
ended March 31, 2006 was $23.2 million (2005 - $22.7 million).
Included in the Trust's property, plant and equipment balance is
$14.1 million, net of accumulated depletion, related to asset
retirement obligations ($20.7 million before accumulated depletion)
(Refer to note 6).
The Trust capitalized approximately $0.6 million of geological and
geophysical compensation costs associated with the exploration and
development of capital assets during the three months ended March 31,
2006 (2005 - $0.4 million).
4. BANK DEBT
March 31 December 31
2006 2005
---------------------------------------------------------------------
Direct advances - 1,326
Banker's acceptances 95,000 70,000
---------------------------------------------------------------------
Total bank debt 95,000 71,326
---------------------------------------------------------------------
---------------------------------------------------------------------
The Trust's credit facilities totaling $215 million are with a
syndicate of banks consisting of a $200 million extendible revolving
term credit facility and a $15 million working capital credit
facility. The facilities are available on a revolving basis for a
period of at least 364 days until May 30, 2006, and such initial term
out date may be extended for further 364 day periods at the request
of the Trust, subject to approval by the banks. Following the term
out date, the facilities will be available on a non-revolving basis
for a one year term, at which time the facilities would be due and
payable. Various borrowing options are available under the facilities
including prime rate based advances and banker's acceptance loans.
Average cost of borrowing under these facilities for the three months
ended March 31, 2006 was 4.5 percent. The credit facilities are
secured by a $500 million fixed and floating charge debenture on the
assets of the Trust and by a guarantee and subordination provided by
Progress in respect of the Trust's obligations. The $215 million
borrowing base is subject to semi-annual review by the banks.
5. CONVERTIBLE DEBENTURES
On February 2, 2005 the Trust issued $100 million principal amount of
6.75 percent convertible unsecured subordinated debentures (the
"Debentures") for net proceeds of $95.5 million. The Debentures pay
interest semi-annually and are convertible at the option of the
holder at any time into fully paid trust units at a conversion price
of $15.00 per trust unit. The Debentures mature on June 30, 2010 at
which time they are due and payable. The Trust may elect to satisfy
the interest and principal obligations of the Debentures by the
issuance of Trust Units. The net proceeds were used to reduce
outstanding bank indebtedness.
The Debentures have been classified as debt net of the fair value of
the conversion feature at the date of issue which has been classified
as part of unitholders' equity and net of issue costs. Issue costs
will be amortized over the term of the Debentures and the debt
portion will accrete up to the principal balance at maturity. The
accretion, amortization of issue costs and the interest paid are
expensed within interest and financing expense on the consolidated
statements of earnings. If Debentures are converted to units, a
portion of the value of the conversion feature under unitholders'
equity will be reclassified to unitholders' capital along with the
conversion price paid. The following table sets forth a
reconciliation of the Debenture activity:
Three Months Ended
March 31
2006 2005
---------------------------------------------------------------------
Debt portion, beginning of period(1) 79,381 90,507
Accretion 145 139
Amortization of issue costs 138 130
Conversions to trust units (20,940) -
---------------------------------------------------------------------
Debt portion, end of period 58,724 90,776
---------------------------------------------------------------------
Equity portion, beginning of period(1) 4,261 4,944
Conversions to trust units (1,124) -
---------------------------------------------------------------------
Equity portion, end of period 3,137 4,944
---------------------------------------------------------------------
Total debentures, end of period 61,861 95,720
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The beginning of period for 2005 is February 2, 2005, the date of
issue of the Debentures.
Total interest charged to earnings for the three months ended
March 31, 2006 was $1.5 million (2005 - $1.3 million) which includes
$0.1 million of debenture accretion (2005 - $0.1 million) and
$0.1 million of amortized issue costs (2005 - $0.1 million).
6. ASSET RETIREMENT OBLIGATIONS
Asset retirement obligations were estimated based on the Trust's net
ownership interest in all wells and facilities, the estimated costs
to abandon and reclaim the wells and facilities and the estimated
timing of the costs to be incurred in future periods. The total
undiscounted amount of the estimated cash flows required to settle
the asset retirement obligations is approximately $52.5 million which
will be incurred over the next 42 years with the majority of costs
incurred between 2009 and 2020. A credit adjusted risk-free rate of
eight percent was used to calculate the fair value of the asset
retirement obligations. The following reconciles the Trust's asset
retirement obligations:
Three Months Ended
March 31
2006 2005
---------------------------------------------------------------------
Balance, beginning of period 20,906 16,065
Liabilities incurred 2,024 199
Liabilities settled (1,527) (202)
Accretion expense 421 326
---------------------------------------------------------------------
Balance, end of period 21,824 16,388
---------------------------------------------------------------------
---------------------------------------------------------------------
7. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES
The non-controlling interest on the consolidated balance sheet
consists of the book value of exchangeable shares issued to Progress
Energy Ltd. shareholders and the fair value of exchangeable shares
issued to Cequel Energy Inc. shareholders as part of a Plan of
Arrangement that became effective on July 2, 2004, plus net earnings
attributable to the exchangeable shares, less exchangeable shares
(and related cumulative earnings) redeemed. The non-controlling
interest charge on the consolidated statement of earnings represents
the share of net earnings attributable to the exchangeable shares
based on the trust units issuable for exchangeable shares in
proportion to total trust units issued and issuable each period end.
Three months ended March 31
---------------------------------------------
2006 2005
---------------------- ----------------------
Number Amount Number Amount
---------------------------------------------------------------------
Exchangeable Shares (Restated Note 2)
Balance, beginning
of period 11,388,751 127,205 14,533,506 141,060
Exchanged for trust
units (1,242,992) (14,145) (1,630,768) (16,001)
Non-controlling interest
expense 3,921 3,940
---------------------------------------------------------------------
Balance, end of period 10,145,759 116,981 12,902,738 128,999
---------------------------------------------------------------------
---------------------------------------------------------------------
The exchangeable shares can be converted, at the option of the
holder, into trust units at any time and are listed on the Toronto
Stock Exchange under the symbol PGE. If the number of exchangeable
shares outstanding is less than 1,600,000, the Trust can elect to
redeem the exchangeable shares for trust units or an amount in cash
equal to the amount determined by multiplying the exchange ratio on
the last business day prior to the redemption date by the current
market price of a trust unit on the last business day prior to such
redemption date. The number of trust units issued upon conversion is
based on the exchange ratio in effect on the date of conversion. 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.
Retraction of Exchangeable Shares
Exchangeable shareholders may redeem their shares at any time by
delivering their share certificates to the Trustee, together with a
properly completed retraction request. The retraction price will be
satisfied with trust units equal to the amount determined by
multiplying the exchange ratio on the last business day prior to the
retraction date by the number of exchangeable shares redeemed.
Redemption of Exchangeable Shares
On July 2, 2009 the exchangeable shares will be redeemed by the Trust
unless the Board of Directors of Progress Energy Ltd. elect to extend
the redemption period. The exchangeable shares will be redeemed by
either issuing units or payment in cash for an amount equivalent to
the value of the exchangeable shares at the current exchange ratio.
8. UNITHOLDERS' CAPITAL
The Trust Indenture provides that an unlimited number of trust units
may be authorized and issued. Each trust unit is transferable,
carries the right to one vote and represents an equal undivided
beneficial interest in any distributions from the Trust and in the
assets of the Trust in the event of termination or winding-up of the
Trust. All trust units are of the same class with equal rights and
privileges.
Trust Units
Three months ended March 31
---------------------------------------------
2006 2005
---------------------- ----------------------
Number Amount Number Amount
---------------------------------------------------------------------
Trust Units (Restated Note 2)
Balance, beginning of
period 71,302,265 681,263 66,898,498 621,490
Exchangeable shares
converted 1,498,125 20,647 1,747,755 23,411
Issued on conversion
of convertible
debentures 1,515,059 22,064 - -
---------------------------------------------------------------------
Balance, end of period 74,315,449 723,974 68,646,253 644,901
---------------------------------------------------------------------
---------------------------------------------------------------------
Redemption Right
Unitholders may redeem their trust units for cash at any time, up to
a maximum value of $250,000 in any calendar month, by delivering
their unit certificates to the Trustee, together with a properly
completed notice requesting redemption. The redemption amount per
trust unit will be the lesser of 90 percent of the simple average
closing price of the trust units on the principal market on which
they are traded for the 10 day trading period after the trust units
have been validly tendered for the redemption and the closing market
price of the trust units on the principal market on which they are
traded on the date on which they were validly tendered for
redemption, or if there was no trade of the trust units on that date,
the average of the last bid and ask prices of the trust units on that
date.
Net Earnings Per Unit
The following table summarizes the weighted average trust units used
in calculating net earnings per unit:
Three Months Ended
March 31
2006 2005
---------------------------------------------------------------------
Weighted average trust units - basic 72,803,846 67,679,785
Trust units issuable on conversion of
exchangeable shares(1) 13,382,852 14,967,938
Performance units 391,814 59,778
---------------------------------------------------------------------
Weighted average trust units - diluted 86,578,512 82,707,501
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Calculated based on the weighted average exchangeable shares
outstanding during the period at the period end exchange ratio.
An adjustment to the numerator of $3.9 million for the three months
ended March 31, 2006 (2005 - $3.9 million) is required in the diluted
earnings per unit calculation to provide for earnings attributable to
non-controlling interest. Units potentially issuable on the
conversion of the Debentures are anti-dilutive and are not included
in the calculation of diluted weighted average units for the three
months ended March 31, 2006.
Performance Unit Incentive Plan
The Trust has established a Performance Unit Incentive Plan (the
"Plan") for employees and directors of the Trust or its subsidiary.
The number of units reserved for issuance under the Plan shall not
exceed 5 percent of the aggregate number of issued and outstanding
units of the Trust and including the number of units which may be
issued on the exchange of the outstanding exchangeable shares, which
may be converted into trust units. Under the Plan, performance units
shall be granted by the Board of Directors of Progress Energy Ltd.
from time to time at its sole discretion. The performance units will
vest on the third anniversary of the date of grant and actual payment
will be determined based on the performance of the Trust relative to
its peers. Performance factors range from 0.5 to 1.5 times the
initial performance units granted. Over the three year term the
performance units will attract distributions. The Trust expects to
pay out the distribution portion in cash while the units earned will
be issued from treasury.
The Board of Directors of Progress Energy Ltd. granted 395,267
performance units effective July 2, 2004. As a result, the fair value
of the performance units granted, calculated using a performance
factor of 1.0, was approximately $5.3 million of which $4.7 million
will be amortized through unit based compensation expense and
$0.6 million will be capitalized over the vesting period with a
corresponding increase to contributed surplus.
The Board of Directors of Progress Energy Ltd. granted 512,500
performance units effective July 2, 2005. The fair value of the
performance units using a performance factor of 1.0 was approximately
$8.0 million of which $6.9 million will be amortized through unit
based compensation expense and $1.1 million will be capitalized over
the vesting period with a corresponding increase to contributed
surplus.
For the three months ended March 31, 2006 $1.0 million was charged to
unit based compensation expense (2005 - $0.5 million) and
$0.2 million (2005 - nil) was capitalized relating to the total
performance units outstanding.
The following table reconciles the Trust's contributed surplus:
Three Months Ended
March 31
2006 2005
---------------------------------------------------------------------
Balance, beginning of period 3,530 171
Unit based compensation expense 1,007 512
Unit based compensation capitalized 164 -
---------------------------------------------------------------------
Balance, end of period 4,701 683
---------------------------------------------------------------------
---------------------------------------------------------------------
9. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital
Three Months Ended
March 31
2006 2005
---------------------------------------------------------------------
Accounts receivable 11,463 4,541
Prepaid expenses and deposits 153 595
Accounts payable (12,909) (2,207)
Current income taxes payable (66) (157)
---------------------------------------------------------------------
Change in non-cash working capital (1,359) 2,772
Relating to:
Financing activities - -
Investing activities (4,057) 1,056
---------------------------------------------------------------------
Operating activities 2,698 1,716
---------------------------------------------------------------------
---------------------------------------------------------------------
Interest and taxes paid
Three Months Ended
March 31
2006 2005
---------------------------------------------------------------------
Interest paid 4,012 560
Income and other taxes paid 405 371
---------------------------------------------------------------------
---------------------------------------------------------------------
10. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
The Trust's financial instruments recognized on the balance sheet
consist of accounts receivable, accounts payable and accrued
liabilities, bank debt and convertible debentures. The fair value of
these instruments, excluding the convertible debentures, approximate
their carrying amounts due to their short terms to maturity or the
indexed rate of interest on the bank debt. The fair value of the
convertible debentures outstanding as at March 31, 2006 was
approximately $72.8 million.
Commodity Price Contracts
The Trust has entered into several derivative natural gas financial
instruments for the purpose of protecting its cash flow from
operations before changes in non-cash working capital from the
volatility of natural gas prices. For the three months ended
March 31, 2006, the Trust's natural gas price risk management program
had a net loss of $0.6 million (2005 - $2.8 million net gain) which
is included in petroleum and natural gas revenue on the statements of
earnings.
Contracts outstanding in respect to financial instruments are as
follows:
Natural Gas Pricing Strike Cost/
Contracts(1) Volume Point Price $/gj Premium Term
---------------------------------------------------------------------
Swap - call 5,000 gj/d AECO Cdn$10.55 - $0.38/gj Apr 01/06 -
spread Cdn$11.55 Oct 31/06
Swap - call 5,000 gj/d AECO Cdn$10.74 - $0.38/gj Apr 01/06 -
spread Cdn$11.74 Oct 31/06
Swap - call 5,000 gj/d AECO Cdn$10.75 - $0.38/gj Apr 01/06 -
spread Cdn$11.75 Oct 31/06
Swap - call 5,000 gj/d AECO Cdn$10.68 - $0.38/gj Apr 01/06 -
spread Cdn$11.68 Oct 31/06
Swap - call 5,000 gj/d AECO Cdn$7.22 - $0.36/gj Apr 01/06 -
spread Cdn$8.22 Oct 31/06
Swap - call 10,000 gj/d AECO Cdn$7.20 - $0.32/gj Apr 01/06 -
spread Cdn$8.20 Oct 31/06
Swap - call 5,000 gj/d AECO Cdn$7.10 - $0.30/gj Apr 01/06 -
spread Cdn$8.10 Oct 31/06
Swap - call 10,000 gj/d AECO Cdn$9.51 - $0.44/gj Nov 01/06 -
spread Cdn$10.51 Mar 31/07
Swap - call 10,000 gj/d AECO Cdn$8.97 - $0.38/gj Nov 01/06 -
spread Cdn$9.97 Mar 31/07
Swap - call 10,000 gj/d AECO Cdn$9.60 - $0.40/gj Nov 01/06 -
spread Cdn$10.60 Mar 31/07
Swap - call 10,000 gj/d AECO Cdn$9.63 - $0.43/gj Nov 01/06 -
spread Cdn$10.63 Mar 31/07
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Call spread strike prices indicate minimum floor and maximum
ceiling
The estimated fair value of the natural gas call spreads, that
qualify for hedge accounting, was a gain of $17.1 million as at
March 31, 2006 and represents the amount the Trust would receive to
terminate the contracts at March 31, 2006. These instruments have no
carrying value recorded in the financial statements.
Commodity Sales Contract
The following physical gas sales contract was outstanding at
March 31, 2006. This contract was acquired in conjunction with the
acquisition of Campion Resources Ltd. on June 3, 2002, at which time
the fair value of the contracts was a liability of $4.1 million. This
value was recorded as a liability on June 3, 2002, and is being
amortized over the life of the contract. At March 31, 2006 the
unamortized remaining liability was $1.3 million.
Volume Pricing Point Progress Price Term
---------------------------------------------------------------------
1,000 gj/d AECO $2.11/gj in 2006 escalating Jun 1/97 -
at 2.5% annually Oct 31/08
---------------------------------------------------------------------
---------------------------------------------------------------------
SELECTED QUARTERLY INFORMATION
FINANCIAL HIGHLIGHTS
Three Months Ended
---------------------------------------------------------------------
2005 2006
---------------------------------------------------------------------
($ thousands except
per unit amounts) March 31 June 30 Sept 30 Dec 31 March 31
---------------------------------------------------------------------
Income Statement
Petroleum and natural
gas revenue 79,007 83,222 93,372 114,167 90,959
Cash flow (1) 42,511 44,466 53,215 65,785 47,637
Per unit - diluted 0.52 0.53 0.64 0.77 0.55
Cash distributions
declared 28,574 28,874 29,210 29,802 30,836
Per unit 0.42 0.42 0.42 0.42 0.42
Net earnings 17,527 16,840 25,159 29,398 21,383
Per unit - basic 0.27 0.25 0.36 0.41 0.29
Per unit - diluted 0.27 0.24 0.36 0.40 0.29
Payout Ratio
Excluding exchangeable
shares 67% 65% 55% 45% 65%
Including exchangeable
shares 81% 79% 66% 54% 76%
Balance Sheet
Capital Expenditures 34,380 13,559 24,492 35,227 35,984
Total debt 187,312 185,708 186,115 173,580 172,106
Unitholders' equity 632,700 623,308 635,630 654,648 687,953
Trust Units (thousands,
except where otherwise
stated)
Units outstanding,
end of period 68,646 68,820 69,956 71,302 74,315
Units issuable for
exchangeable shares 13,992 14,281 13,601 13,482 12,309
---------------------------------------------------------------------
Total units outstanding
and issuable for
exchangeable shares,
end of period 82,638 83,101 83,557 84,784 86,624
Weighted average units
- diluted(2) 82,485 83,176 83,700 84,675 86,579
Exchange ratio, end
of period 1.08438 1.12038 1.15421 1.18384 1.21322
Trust Unit Trading
Statistics ($)
High 14.50 13.79 17.82 17.85 18.20
Low 12.52 11.90 13.07 14.08 14.75
Closing 13.38 13.03 17.61 17.17 17.45
Unit volume traded
(thousands) 17,788 11,544 19,159 18,385 18,619
Exchangeable Shares
Trading Statistics ($)
High 15.85 15.50 20.62 20.36 21.29
Low 13.96 13.27 15.00 16.61 18.49
Closing 14.60 14.96 19.26 20.36 20.70
Share volume traded
(thousands) 1,460 290 613 52 85
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Refer to discussion in the Management Discussion and Analysis
(2) Includes exchangeable shares converted at the end of period
exchange ratio.
SELECTED QUARTERLY INFORMATION
OPERATIONAL HIGHLIGHTS
Three Months Ended
---------------------------------------------------------------------
2005 2006
---------------------------------------------------------------------
March 31 June 30 Sept 30 Dec 31 March 31
---------------------------------------------------------------------
Daily Production
Natural gas (mcf/d) 84,523 79,236 80,804 85,173 86,433
Crude oil (bbls/d) 2,550 3,067 2,734 2,762 2,605
Natural gas liquids
(bbls/d) 1,598 1,305 1,280 1,355 1,390
Total daily production
(boe/d) 18,235 17,578 17,481 18,312 18,401
Average Realized Prices
Natural gas - before
hedging ($/mcf) 7.31 8.12 9.33 12.18 8.80
Natural gas - after
hedging ($/mcf) 7.69 8.13 9.11 11.38 8.74
Crude oil ($/bbl) 59.44 64.20 72.66 67.22 64.45
Natural gas liquids
($/bbl) 47.82 56.41 62.68 63.63 62.86
Highlights ($/boe)
Weighted average
sales price 48.14 52.02 58.06 67.77 54.92
Royalties 11.78 13.16 14.39 18.38 14.87
Operating expenses 5.69 5.72 5.70 5.66 5.81
Transportation expenses 1.89 1.98 1.95 1.89 1.91
---------------------------------------------------------------------
Operating Netbacks 28.78 31.16 36.02 41.84 32.33
General and
administrative expense 1.23 1.33 0.83 0.75 1.08
Unit based compensation 0.31 0.32 0.62 0.59 0.61
Interest and financing
expenses 1.26 1.80 1.80 1.62 1.45
Depletion, depreciation
and accretion 14.05 14.19 14.26 13.86 14.27
---------------------------------------------------------------------
Net earnings before
taxes 11.93 13.52 18.51 25.02 14.92
Capital taxes 0.33 0.34 0.34 0.32 0.20
Future income taxes
(recovery) (1.48) 0.55 (0.63) 3.93 (0.56)
Non-controlling interest
- exchangeable shares 2.40 2.10 3.16 3.32 2.37
---------------------------------------------------------------------
Net earnings 10.68 10.53 15.64 17.45 12.91
---------------------------------------------------------------------
---------------------------------------------------------------------
Drilling Results
Gross 24 8 24 31 39
Net - natural gas 9.9 3.3 9.6 16.0 18.8
Net - crude oil 1.2 0.0 1.9 1.7 0.8
Success Rate (percent) 89 78 89 100 93
---------------------------------------------------------------------
---------------------------------------------------------------------
