EPCOR Announces Quarterly Results
EDMONTON, Nov. 5 /CNW/ - EPCOR Utilities Inc. (EPCOR) today released its
quarterly results for the period ended September 30, 2008.
"The third quarter saw EPCOR reach milestones in our capital and
maintenance programs," said EPCOR President and CEO Don Lowry. "EPCOR and its
contractors substantially completed the Downtown Edmonton Supply Substation
and transmission project, which was energized on October 29, and our power and
water businesses operated solidly during the quarter.
On October 10, 2008, Genesee 3 came off line due to a rotor blade failure
and the unit is expected to be off line until approximately the end of
November 2008. We are working with our employees, partners and suppliers to
place the unit back into service as soon as possible.
We are also witness to a serious financial crisis that is gripping the
world financial markets and we are not immune from its impacts. We are
carefully managing our operations, capital and financing plans to sustain our
cash flows and ensure we continue to provide reliable power and water
services."
Highlights of EPCOR's financial performance:
- Cash flow from operating activities for the three months ended
September 30, 2008 was $139 million compared with $149 million for
the corresponding period in the previous year.
- Cash flow from operating activities for the nine months ended
September 30, 2008 was $278 million compared with $368 million for
the corresponding period in the previous year.
- Net income was $76 million on revenues of $967 million for the three
months ended September 30, 2008 compared with $67 million on revenues
of $930 million for the corresponding period in the previous year.
- Net income was $160 million on revenues of $2,631 million for the
nine months ended September 30, 2008 compared with $218 million on
revenues of $2,694 million for the corresponding period in the
previous year.
- Other comprehensive income was $6 million for the three months ended
September 30, 2008 compared with other comprehensive loss of
$24 million for the corresponding period in the previous year.
- Other comprehensive income was $30 million for the nine months ended
September 30, 2008 compared with other comprehensive loss of
$27 million for the corresponding period in the previous year.
- Investment in capital projects for the three months ended
September 30, 2008 was $171 million compared with $144 million for
the corresponding period in the previous year.
- Investment in capital projects for the nine months ended
September 30, 2008 was $465 million compared with $331 million for
the corresponding period in the previous year.
Management's discussion and analysis (MD&A) of the quarterly results are
shown below. The MD&A and the unaudited interim financial statements are
available on EPCOR's website (www.epcor.ca), and will be available on SEDAR
(www.sedar.com).
EPCOR's wholly-owned subsidiaries build, own and operate power plants,
electrical transmission and distribution networks, water and wastewater
treatment facilities and infrastructure in Canada and the United States.
EPCOR, headquartered in Edmonton, Alberta, has been named one of Canada's Top
100 employers for nine consecutive years, and was selected one of Canada's 10
Most Earth-Friendly Employers. EPCOR's website is www.epcor.ca.
EPCOR Utilities Inc.
Interim Management's Discussion and Analysis
September 30, 2008
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This management's discussion and analysis (MD&A), dated November 5, 2008,
should be read in conjunction with the unaudited interim consolidated
financial statements of EPCOR Utilities Inc. (hereinafter "the Company",
"EPCOR", "we", "our" or "us") for the three and nine months ended
September 30, 2008 and 2007, the audited consolidated financial statements and
MD&A for the year ended December 31, 2007 and the cautionary statement
regarding forward-looking information on page 27. EPCOR is a wholly-owned
subsidiary of The City of Edmonton. Financial information in this MD&A is
based on the unaudited interim consolidated financial statements, which were
prepared in accordance with Canadian generally accepted accounting principles
(GAAP), and is presented in Canadian dollars unless otherwise specified. In
accordance with its terms of reference, the Audit Committee of the Company's
Board of Directors reviews the contents of the MD&A and recommends its
approval by the Board of Directors. The Board of Directors has approved this
MD&A upon the recommendation of the Audit Committee.
OVERVIEW
EPCOR's results from operating activities for the third quarter returned
to more normal levels after three major turnarounds for scheduled maintenance
at our Genesee facilities in the first two quarters. Generation from all three
plants increased, maintenance expenses declined and availability incentive
income under the terms of the Genesee Power Purchase Arrangement (PPA)
increased, compared with the previous quarter. Generally, the generation fleet
operated on plan during the quarter. Income from Energy Services operations
was down from the second quarter as Alberta power prices declined in the third
quarter. However, despite the decrease in Alberta power prices we managed our
commodity positions well, contributing to solid earnings for the quarter. Our
water and electric distribution and transmission businesses operated solidly
during the quarter.
EPCOR Power L.P. (Power LP), a 30.6% subsidiary of EPCOR, contributed a
net loss in the quarter due to fair value changes, primarily on natural gas
supply contracts, which substantially offset the fair value gains on these
contracts in the first two quarters of the year. Fair value changes can cause
volatility in Power LP's earnings but are not representative of the underlying
economic performance of Power LP's business. Operating margins, excluding fair
value changes, from Power LP's plants were $3 million lower in the third
quarter compared with the third quarter of 2007.
Progress continued on our capital expenditure program, particularly the
Keephills 3 generation plant and the two remaining units at Clover Bar Energy
Centre. The first unit at Clover Bar Energy Centre was commissioned in the
first quarter of 2008. The Downtown Edmonton Supply and Substation and
transmission line (DESS) were substantially completed in the third quarter and
energized on October 29, 2008.
In the third quarter, Distribution and Transmission negotiated a
settlement with customer groups on its 2007-2009 Distribution and Transmission
Tariff Application. The approved rates were slightly higher than interim
rates, resulting in the recognition of revenue adjustments for the January 1,
2007 to September 30, 2008 period, in the third quarter.
The timing of the restructuring of asset-backed commercial paper (ABCP)
has been delayed again from earlier estimates due to complexities of the
restructuring and market volatility. The Pan-Canadian Investors Committee
(Investors Committee) overseeing the restructuring anticipates that the
restructuring will be completed by the end of November 2008. There was no
significant change in our ABCP holdings or assessment of their fair value in
the quarter.
SIGNIFICANT EVENTS
EPCOR Power L.P. to acquire Illinois co-generation facility
On September 11, 2008, Power LP announced an agreement to acquire a 100%
equity interest in Morris Cogeneration LLC (Morris) from Diamond Generating
Corporation and MIC Nebraska, Inc., both wholly-owned subsidiaries of
Mitsubishi Corporation for an aggregate purchase price of US$77 million
subject to finalizing closing adjustments. The purchase price has since been
estimated at US$73 million as preliminary closing adjustments have been
determined. Morris is a 177 megawatt (MW) natural gas-fired cogeneration
facility located on Equistar Chemicals LP's (Equistar) chemical plant in
Morris, Illinois.
The acquisition closed on October 31, 2008 and will be financed under the
Power LP's existing credit facilities with permanent long-term financing to be
arranged after the close of the transaction, depending on the requirements of
Power LP.
All of the steam and a portion of the electricity produced from Morris
are sold to Equistar under the terms of a long-term energy services agreement
which expires in 2023. Equistar, a wholly-owned subsidiary of Lyondell
Chemical Company, produces ethylene and its co-products and derivatives
including polyethylene plastic, at its plant in Morris. Morris also has an
electric capacity agreement with Exelon Generation Company, LLC (Exelon) that
terminates in 2011, for capacity and electricity of 100 MW. Any excess
capacity and energy above the needs of Exelon and Equistar may be sold into
the Pennsylvania, New Jersey, and Maryland market.
Asset-backed commercial paper
At September 30, 2008, the Company held $49 million ($71 million original
cost) in Canadian non-bank sponsored ABCP, all of which was purchased during
the third quarter of 2007. The Company's ABCP is part of the broader
$35 billion ABCP market that has been disrupted by the significant lack of
liquidity that emerged in August 2007 and as a result, all of the Company's
ABCP matured with no payment of principal, accrued interest or roll over.
An Investors Committee comprised of a consortium representing banks,
asset providers and major investors, is overseeing the proposed restructuring
of the ABCP. In March 2008, the Investors Committee distributed to affected
ABCP investors an information package and voting materials in respect of the
restructuring. Under the proposed restructuring, the affected ABCP would be
converted into term floating-rate notes (notes) maturing no earlier than the
scheduled termination dates of the underlying assets. The restructuring
documents and subsequent presentations and conference calls provided
additional information and clarification on the proposed restructuring. The
key information as it relates to EPCOR is as follows:
(i) EPCOR expects its breakdown of new notes under the proposed
restructuring, based on EPCOR's original book value of the
investments, to be as follows:
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Pool Series Rating Amount
($ millions)
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MAV2 Class A-1 AA $ 48 67%
Class A-2 AA 9 13%
Class B Unrated 2 2%
Class C Unrated 1 2%
MAV3 IA Tracking Unrated 11 16%
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$ 71 100%
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(ii) For the Master Asset Vehicle 2 (MAV2) pool notes (84% of the new
notes EPCOR expects to receive), the underlying asset lives are
anticipated to average nine years. The remaining notes are
expected to come from Master Asset Vehicle 3 (MAV3) in the form of
Ineligible Asset Tracking (IA Tracking) notes which represent 16%
of the new notes EPCOR expects to receive. These notes are
expected to amortize over the lives of the underlying assets which
have a weighted average life of approximately 18 years. Under the
proposed restructuring, in certain limited circumstances, the
expected repayment dates could be longer than the expected asset
lives.
(iii) ABCP investors, including EPCOR, expect to be paid the accumulated
accrued interest, net of any restructuring fees, collateral
requirements and other costs, on their existing ABCP from the date
of the standstill in August 2007 to the date of the restructuring.
(iv) The costs of the restructuring are factored into but are not
material to our valuation.
(v) The March 2008 note-holder information included indicative
valuation data on the various ABCP conduits which was used by the
Investors Committee for allocating the existing notes among the
classes and series of new notes. EPCOR considered this information
in assessing its valuation.
On April 25, 2008, ABCP investors voted in favour of the proposed
restructuring plan. After extending the time for his review, on June 6, 2008,
the judge presiding over the restructuring process ruled that the
restructuring plan was fair after giving effect to amendments to the
restructuring to allow for certain claims for fraud. Certain ABCP note-holders
filed motions with the Ontario Appeals Court for leave to appeal the ruling
subsequent to which, on September 19, 2008, the appeal was denied. A further
appeal was taken to the Supreme Court of Canada which was denied on
October 17, 2008. This final decision cleared the way for the restructuring to
proceed. On October 20, 2008, the Investors Committee announced that the
restructuring is taking longer to complete than previously anticipated due to
its complexity and market volatility, and they now expect the restructuring
will be completed by the end of November 2008.
EPCOR's ABCP is a financial instrument and is classified as held for
trading and therefore is recorded at fair value. EPCOR's estimate of the fair
value of its ABCP at September 30, 2008 was $49 million compared with
$60 million at December 31, 2007. The estimated fair value decreased by
$11 million ($2 million for the quarter) primarily due to lower interest
rates, higher observed and estimated credit spreads over the yields of
long-term Government of Canada bonds and longer expected note lives based on
new information provided by the Investors Committee. EPCOR estimated the fair
value using a probability-weighted discounted cash flow approach based on the
assumed credit ratings and potential ratings actions on the applicable ABCP
conduits under the proposed restructuring, observable interest rates and
credit spreads for estimating future interest payments and applicable discount
rates, the cost of margin call facilities, the cost of the proposed
restructuring, estimated recovery periods based on the estimated lives of the
underlying assets of the proposed restructuring conduits and ranges of
recoverability based on publicly available default statistics for credit-rated
entities. In estimating future cash flows from ABCP the Company assumed that
it would earn interest at rates ranging from 2.78% to 3.58% (weighted average
rate of 3.00%) depending on the note series, taking into account restructuring
costs and margin funding. The future cash flows were discounted at rates
ranging from 6.69% to 25.10% (weighted average rate of 9.40%), depending on
the note series, over 8.2 to 8.3 years (weighted average amortization period
of 8.2 years), taking into account the assumed credit spreads and mortality
rates.
The estimate of fair value of ABCP is subject to significant risks and
uncertainties including the timing and amount of future cash payments, market
liquidity, the quality and tenor of the underlying assets and instruments in
the applicable conduits including the possibility of margin calls, and the
future market for the restructured notes. Accordingly, the estimate of fair
value of ABCP may change materially as events unfold and more information
becomes available.
The Company continues to be in compliance with the financial covenants of
its credit facilities and publicly issued debt and has sufficient credit
facilities and cash flows from operations to satisfy its financial obligations
as they come due. Based on current information, the Company does not expect
there will be a material adverse impact on its business as a result of this
current ABCP liquidity issue.
CONSOLIDATED RESULTS OF OPERATIONS
Net income
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(Unaudited, $ millions) Three Nine
months months
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Net income for the periods ended September 30, 2007 $ 67 $ 218
Unrealized fair value changes on derivative
instruments and natural gas inventory held for
trading, excluding Power LP fair value changes 31 11
Gains on sales of portfolio investments 7 9
Lower (higher) interest expense and preferred share
dividends, excluding Power LP interest expense and
preferred share dividends 6 (3)
Higher Distribution and Transmission energy margins 5 9
Higher margins for trading activities in the north
eastern U.S. and Ontario 4 6
Higher water rates 3 11
Higher (lower) operating income from Genesee 1, 2
and 3, excluding PPA availability and capacity
revenue 2 (22)
Impact of recording a net future income tax asset
associated with the Energy Services reorganization
on January 1, 2007 - (10)
Fair value reduction in ABCP (2) (11)
Higher (lower) Alberta energy margins (3) 14
Lower Genesee PPA availability and capacity payment
income (5) (30)
Higher administration expenses, excluding Power LP
administration (13) (24)
Lower income from Power LP (28) (19)
Other 2 1
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Increase (decrease) in net income 9 (58)
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Net income for the periods ended September 30, 2008 $ 76 $ 160
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Net income was $76 million and $160 million for the three and nine months
ended September 30, 2008 respectively, compared with $67 million and
$218 million for the corresponding periods in 2007. The changes were due to
the net impact of the following:
- In the third quarter of 2008, the unrealized fair value changes in
our financial electricity contracts, Joffre contract-for-differences
(CfD) and forward foreign exchange contracts were all favourable
compared with the third quarter of 2007. For the nine months ended
September 30, 2008, the unrealized fair value changes in our forward
foreign exchange contracts were favourable and the fair value changes
in our financial electricity contracts and the Joffre CfD were
unfavourable compared to the prior year period.
- Excluding Power LP subsidiary preferred share dividends, there were
no preferred share dividends in 2008 as the Company's other
subsidiary preferred shares were redeemed on September 30, 2007. In
2007, preferred share dividends for the first two quarters were more
than offset by a reduction in the second quarter reflecting the
substantive enactment of an income tax rate reduction attributable to
preferred share dividends paid commencing in 2003. Interest expense,
excluding Power LP interest expense, was higher primarily due to
higher debt balances following the $200 million and $400 million
public debt offerings in January and April 2008, respectively, partly
offset by higher capitalized interest as a result of increased
capital construction activity.
- In the third quarter of 2008, Distribution and Transmission
negotiated a settlement agreement (NSA) with customer groups on its
2007-2009 General Tariff Application and the impact of the tariff
increases compared to Distribution and Transmission's interim rates,
including the retroactive portion, was recognized in September 2008.
Distribution and Transmission's margins in all three quarters of 2008
also reflect higher interim rates, and volumes due to growth in the
Edmonton franchise area, compared with the corresponding periods in
2007.
- Margins on power trading activities in the north eastern United
States (U.S.) and Ontario were higher in 2008 primarily due to wider
spreads between Ontario and the north eastern U.S. power prices.
- Water revenues, net of franchise fees, were higher primarily due to
rate increases which became effective on April 1, 2007 and April 1,
2008.
- The changes in operating income from Genesee 1, 2 and 3 were
primarily due to maintenance activities. In the third quarter,
maintenance expenses for Genesee outages were lower as there were no
planned outages in 2008 compared with one outage at Genesee 1 in the
third quarter of 2007. The nine month periods reflect three major
turnarounds at our Genesee facilities in the first two quarters of
2008 compared with no outages in the first two quarters of 2007.
Regular maintenance work for all three units was also higher in the
nine months ended September 30, 2008 compared with the corresponding
period in 2007.
- On January 1, 2007, the Company reorganized two subsidiaries within
the Energy Services segment that operate the regulated retail
business. As part of the reorganization, one of the subsidiaries,
which was previously exempt from income taxes became subject to
income tax under the Income Tax Act and recognized future income tax
assets of $10 million and a corresponding reduction in income tax
expense. There was no similar transaction in 2008.
- In the third quarter of 2008, margins for the procurement, marketing
and sale of electricity in retail and wholesale markets in Alberta
(Alberta electricity margins) were lower compared with the
corresponding period in 2007 primarily due to lower margins from the
Joffre plant as a result of plant outages and lower margins from our
interests in the Battle River and Sundance Power Purchase
Arrangements (acquired PPAs) due to lower Alberta power prices. The
decreases were partly offset by higher gains on derivative financial
contracts used to hedge the exposure to Alberta power prices,
compared with the prior year.
Alberta electricity margins increased for the nine months ended
September 30, 2008 compared with the corresponding period in 2007
primarily due to increased length in the portfolio of derivative
financial contracts that settled at higher Alberta power prices.
These increases were partly offset by lower generation from the
Joffre and Genesee 3 facilities as a result of plant outages, and
lower margins from our acquired PPAs.
- In the third quarter of 2008, availability incentive revenue earned
under the terms of the Genesee 1 and 2 PPA was lower than in the
corresponding period in 2007 due to recognition of availability
incentive income in 2007 arising from a significant reduction in the
number of outage days for 2007. For the nine month period, a net
availability penalty was incurred in 2008 compared with availability
incentive revenue recognized in 2007. The net penalty in 2008 was due
to the major outages at these units in the first two quarters.
Capacity payment revenue under this PPA was also lower due to a lower
return from a declining PPA rate-base and reduced tax recoveries
related to lower federal income tax rates.
- Administration expenses, excluding Power LP's administration, were
higher in the first nine months of 2008 compared with the
corresponding period in 2007 primarily due to an increase in the
Company's estimated liability for its Long-Term Incentive Plan (LTIP)
in the third quarter of 2008 and a reduction of the liability in the
first quarter of 2007. A similar but smaller reduction of the
liability was recorded in the first quarter of 2008. The LTIP is a
notional stock option plan for senior management. Adjustments are
recorded based on the results of the quarterly valuations of the
plan. In addition, in the first nine months of 2008, costs for
regulatory proceedings, bad debt provisions, business development and
employees were higher compared with the corresponding period in the
prior year.
- Net income from Power LP was lower in the third quarter of 2008
compared with the corresponding period in 2007 primarily due to
unrealized changes in the fair value of natural gas supply and
forward foreign exchange contracts, and the foreign currency
translation of U.S. debt. In the nine months ended September 30,
2008, net income from Power LP was lower primarily due to unrealized
changes in the fair value of forward foreign exchange contracts and
foreign currency translation of U.S. debt, partly offset by
favourable changes in the fair value of natural gas supply contracts
compared with the prior year. Power LP's plant operating margins were
slightly lower in the nine months ended September 30, 2008 compared
with the corresponding period in 2007, primarily due to a milestone
payment made for the Frederickson plant under the terms of a long-
term service agreement with the turbine manufacturer, lower revenue
and generation from the Manchief plant in Colorado due to higher
natural gas prices and higher fuel costs at the Greeley plant in
Colorado.
Revenues
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(Unaudited, $ millions) Three Nine
months months
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Revenues for the periods ended September 30, 2007 $ 930 $ 2,694
Higher Water Services' commercial and
transportation services revenues 29 46
Unrealized fair value changes on derivative
instruments and natural gas inventory held for
trading, excluding Power LP fair value changes 27 (14)
Higher trading activities in the north eastern
U.S. and Ontario 25 44
Sale of portfolio investments 10 13
Higher Distribution and Transmission tariff revenues 6 5
Higher water rates 3 12
Lower Genesee PPA availability and capacity
payment revenues (8) (42)
Lower energy revenues from trading activities
in the western U.S. (14) (5)
Lower Power LP revenues (16) (55)
Lower Alberta energy revenues (18) -
Lower physical natural gas trading activities (22) (81)
Other revenues 15 14
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Increase (decrease) in revenues 37 (63)
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Revenues for the periods ended September 30, 2008 $ 967 $ 2,631
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Consolidated revenues were higher for the three months and lower for the
nine months ended September 30, 2008 compared with the corresponding periods
in 2007. Further information on the year-over-year changes is as follows:
- Commercial and transportation services revenues were higher primarily
due to new water and wastewater facility construction contracts with
the City of Wetaskiwin, the Towns of Taber and Chestermere, and Suncor
Voyageur Energy, which were entered into in the fourth quarter of 2007
and in 2008.
- Unrealized fair value gains on derivative financial sell contracts
that were not designated as hedges for accounting purposes were higher
due to larger decreases in forward Alberta power prices for the three
months ended September 30, 2008 compared with the corresponding period
in 2007.
For the nine months ended September 30, 2008, the favourable variances
noted above for the third quarter were more than offset by higher
unrealized fair value losses on derivative financial sell contracts in
the first two quarters of 2008 compared with the first two quarters of
2007. The losses were higher due to an increased volume of financial
sell contracts and larger increases in the forward Alberta power
prices in 2008.
- In 2008, Distribution and Transmission revenues reflect the tariff
increases included in the NSA, partly offset by higher rebates from
the Alberta Balancing Pool, which are passed on to customers and
recognized as a reduction of revenue. These flow-through rebates
correspondingly reduce Distribution and Transmission's expenses.
- Water sales were higher primarily due to a rate increase effective
April 1, 2007 and an additional smaller increase effective April 1,
2008.
- Revenues from Power LP were lower primarily due to unrealized fair
value changes on forward foreign exchange contracts for U.S. dollars
used to hedge U.S. dollar operating cash flows, partly offset by
higher plant revenues. Revenues from the California facilities were
higher as natural gas cost increases were passed on to the
counterparties to the facilities' power purchase agreements. Ontario
plant revenues were higher due to built-in annual price escalators and
increased enhancement activity resulting from higher natural gas
prices. These increases in plant revenues were partly offset by lower
natural gas sales at the Castleton plant.
- In the three months ended September 30, 2008, revenues for sales of
electricity in the retail and wholesale markets in Alberta (Alberta
electricity revenues) were lower compared with the corresponding
period in 2007 primarily due to decreased generation and lower
ancillary services revenue from the Joffre plant due to outages, and
lower electricity revenue from our Regulated Rate Tariff (RRT)
customers due to lower consumption. Ancillary services are provided to
the Alberta Electric System Operator to ensure that the interconnected
electric system is operated in a manner that provides a satisfactory
level of service with acceptable levels of voltage and frequency.
Alberta electricity revenues for sales to our RRT customers were
higher in the nine months ended September 30, 2008 primarily due to
higher pricing, partly offset by lower volumes. Revenues from our
acquired PPAs were also higher due to higher Alberta power prices. The
increases were offset primarily by an increased volume of derivative
financial sell contracts that settled at losses in 2008. The contracts
were used to hedge Alberta power price exposure on electricity sales.
Capital spending and investment
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(Unaudited, $ millions)
Nine months ended September 30 2008 2007
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Generation $ 306 $ 155
Distribution and Transmission 94 72
Energy Services 5 8
Water Services 50 82
Corporate - other 10 14
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$ 465 $ 331
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Capital expenditures for property, plant and equipment were higher for
the nine months ended September 30, 2008 compared with the corresponding
period in 2007 primarily due to increased construction activity on the
Keephills 3 and Clover Bar Energy Centre generation projects and on the DESS
project in Distribution and Transmission.
Keephills 3 is a 495-MW supercritical coal-fired generation plant which
is a joint development of EPCOR and TransAlta Corporation at TransAlta's
Keephills site. We continue to manage the schedule and costs of our Keephills
project with it on track to achieve commercial operations by the end of the
first quarter of 2011. To date, we have mitigated our exposure to rising steel
prices through early procurement, and 55% of the project cost is now fixed
through work completed to date and fixed price contracts. We still have
exposure to the Alberta labour market having completed approximately 25% of
the total labour hours related to the project. Should this tight market
continue or worsen, we would expect to see increasing pressure on costs which
could result in up to a 10% increase in the final cost of the project. We
continue to monitor this with our partner on a regular basis and overall the
project continues to track to plan.
The Clover Bar Energy Centre will be composed of three natural gas-fired
peaking power generation units. The first unit was commissioned in the first
quarter of 2008 and construction of the remaining two units will continue
through 2010. The current estimated final cost for the project is $284
million, up slightly from earlier estimates.
In the first quarter of 2007, Distribution and Transmission commenced
construction of the DESS project which consists of a new high-voltage
transmission line, which will supply electricity to downtown Edmonton. The
project was substantially completed in the third quarter of 2008.
Water Services' construction on the E.L. Smith water treatment plant
upgrade continued in 2008, but spending decreased compared with 2007 as the
project was substantially completed in the second quarter.
In January 2007, we announced that we would re-examine the design and
schedule of the Kingsbridge II wind power development project in Ontario. In
October 2008, we announced that the Company and the Ontario Power Authority
mutually agreed to terminate the renewable energy supply agreement for the
project. Accordingly, EPCOR will not proceed with the project as originally
planned and is considering the future of the project. We did not incur any
asset write-downs as a result of the decision.
SEGMENT RESULTS
Generation
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Generation results
(including intersegment
transactions) Three months ended Nine months ended
(Unaudited, $ millions) September 30 September 30
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2008 2007 2008 2007
Revenues $ 257 $ 268 $ 712 $ 777
Expenses 367 223 617 552
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Operating income $ (110) $ 45 $ 95 $ 225
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(Unaudited, $ millions) Three Nine
months months
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Operating income for the periods ended
September 30, 2007 $ 45 $ 225
Unrealized fair value changes on derivative
instruments 16 18
Gain on sale of portfolio investments 10 13
Higher (lower) operating income from Genesee
1, 2 and 3, excluding PPA availability
and capacity revenue 3 (33)
Higher business development expenses (4) (1)
Lower Genesee PPA availability and capacity
payment revenues (8) (42)
Lower Power LP operating income (167) (79)
Other (5) (6)
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Decrease in operating income (155) (130)
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Operating income for the periods ended
September 30, 2008 $ (110) $ 95
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Generation's operating income for the quarter and nine months ended
September 30, 2008 decreased $155 million and $130 million respectively, over
the corresponding periods in 2007. Further information on the year-over-year
changes is as follows:
- Unrealized fair value changes on derivative financial instruments were
favourable in the three and nine months ended September 30, 2008
compared with the corresponding periods in 2007. In the third quarter
of 2008, the unrealized change in the fair value of the Joffre CfD was
$8 million favourable compared with the corresponding period in 2007
primarily due to a favourable forward spark spread in the current
quarter. Spark spread represents the difference between power prices
and the cost of natural gas required to produce electricity. If the
price of power is higher than the cost of natural gas to produce
electricity, the spark spread is favourable and vice versa. In the
nine months ended September 30, 2008, the unrealized change in fair
value was $4 million unfavourable compared with the corresponding
period in 2007 primarily due to a decrease in forward natural gas
prices in 2007.
Generation uses forward foreign exchange contracts for U.S. dollars to
hedge anticipated equipment and materials purchases related to the
Clover Bar Energy Centre and Keephills 3 projects. The unrealized fair
value changes on these contracts were $8 million and $22 million more
favourable in the three and nine months ended September 30, 2008,
respectively, compared with the corresponding periods in 2007 due to
strengthening U.S. dollar forward prices in 2008 and a weakening in
2007.
The impact of the unrealized fair value changes for both the Joffre
CfD and the forward foreign exchange contracts was to decrease
revenues and expenses by $5 million and $21 million respectively, in
the third quarter of 2008 and to increase revenues and decrease
expenses by $2 million and $16 million respectively, in the nine
months ended September 30, 2008 compared with the corresponding
periods in the prior year.
- The changes in operating income from Genesee 1, 2 and 3 were primarily
due to maintenance activities. In the third quarter of 2008,
maintenance expenses related to Genesee were lower as there were no
planned outages in 2008 compared with one outage at Genesee 1 in the
third quarter of 2007. The nine month periods reflect three major
turnarounds in the first two quarters of 2008 compared with no outages
in the first two quarters of 2007. The turnarounds in 2008 were for
required maintenance and were scheduled back-to-back to accommodate
the Alberta Electric System Operator's upgrade of the new high-voltage
transmission lines in the Genesee and Keephills area. The timing of
the outages coincided with periods of high Alberta power prices which
resulted in significant availability penalties under the terms of the
PPA for Genesee 1 and 2. Regular maintenance work for all three units
was also higher in the nine months ended September 30, 2008 compared
with the corresponding period in 2007.
- Power LP contributed an operating loss of $168 million in the third
quarter and operating income of $14 million in the first nine months
of 2008. In 2007, Power LP contributed an operating loss of $1 million
in the third quarter and operating income of $93 million in the first
nine months. These decreases in operating income were primarily due to
changes in the fair value of natural gas supply and forward foreign
exchange contracts, and the translation of U.S. debt.
Power LP's revenues decreased $16 million in the third quarter and $55
million in the first nine months of 2008 compared with the
corresponding periods in the prior year, primarily due to unrealized
changes in the fair value of forward foreign exchange contracts for
U.S. dollars used to hedge operating cash flow resulting from a
strengthening U.S. dollar in 2008 compared with a weakening U.S.
dollar in 2007. The decreases were partly offset by higher revenues at
Power LP's California and Ontario facilities.
Power LP's expenses were $151 million higher in the third quarter of
2008 compared with the corresponding period in the prior year.
Unrealized losses for changes in the fair value of the natural gas
supply contracts, which were included in fuel expense, were $108
million higher in 2008 due to decreases in forward natural gas prices.
Foreign exchange expense was $40 million higher in 2008 primarily due
to a loss on the translation of Power LP's U.S. dollar debt due to a
strengthening U.S. dollar, compared with a gain in 2007 due to a
weakening U.S. dollar. Fuel costs for the California and North
Carolina plants were also higher due to increased natural gas and coal
prices.
In the nine months ended September 30, 2008, Power LP's expenses were
$24 million higher compared with the corresponding period in 2007.
Foreign exchange expense was $83 million higher in 2008 primarily due
to a loss on the translation of U.S. dollar debt compared with a gain
in 2007, partly offset by realized losses in the first two quarters of
2007 on foreign exchange contracts entered into in anticipation of
permanent financing of acquisitions completed in 2006, and losses
realized in 2007 on interest rate contracts. The changes in foreign
exchange were due to a strengthening U.S. dollar in the nine months
ended September 30, 2008 compared with a weakening U.S. dollar in the
corresponding period in 2007. Fuel costs were lower due to the fair
value changes on the natural gas contracts which resulted in an
unrealized gain of $10 million in 2008 compared with an unrealized
loss of $68 million in 2007. This decrease in fuel costs was partly
offset by higher fuel costs for the Ontario, California and North
Carolina plants.
Distribution and Transmission
-------------------------------------------------------------------------
Distribution and Transmission results
(including intersegment transactions)
Three months ended Nine months ended
(Unaudited, $ millions) September 30 September 30
-------------------------------------------------------------------------
2008 2007 2008 2007
Revenues $ 72 $ 63 $ 190 $ 181
Expenses 58 52 158 150
-------------------------------------------------------------------------
Operating income $ 14 $ 11 $ 32 $ 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Distribution and Transmission revenues were $9 million higher for both the
three and nine months ended September 30, 2008, compared with the
corresponding periods in the prior year. In the third quarter of 2008,
Distribution and Transmission negotiated a settlement agreement with customer
groups on its 2007-2009 General Tariff Application. Accordingly, Distribution
and Transmission's revenues reflect the tariff increases agreed to in the NSA,
including the retroactive portion. This increase in revenues was partly offset
by higher rebates from the Alberta Balancing Pool in 2008, which are passed on
to customers and recognized as a reduction of revenues. Expenses were also
higher in the three and nine months ended September 30, 2008 compared with the
same periods in 2007, primarily due to administration expenses incurred for
the NSA proceeding, and partly offset by higher rebates received from the
Alberta Balancing Pool. Distribution and Transmission expects the Alberta
Utilities Commission's (AUC) approval of the NSA in the fourth quarter of
2008.
Energy Services
-------------------------------------------------------------------------
Energy Services results
(including intersegment
transactions) Three months ended Nine months ended
(Unaudited, $ millions) September 30 September 30
-------------------------------------------------------------------------
2008 2007 2008 2007
Revenues $ 608 $ 599 $ 1,703 $ 1,759
Expenses 531 548 1,621 1,683
-------------------------------------------------------------------------
Operating income $ 77 $ 51 $ 82 $ 76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Unaudited, $ millions) Three Nine
months months
-------------------------------------------------------------------------
Operating income for the periods ended
September 30, 2007 $ 51 $ 76
Unrealized fair value changes in derivative
instruments and natural gas inventory 25 (12)
Higher energy margin from trading
activities in the north eastern U.S. and Ontario 6 9
Higher (lower) RRT non-energy charge revenue 3 (2)
Higher bad debt expense (3) (3)
Higher (lower) Alberta electricity margins (4) 18
Other (1) (4)
-------------------------------------------------------------------------
Increase in operating income 26 6
-------------------------------------------------------------------------
Operating income for the periods ended
September 30, 2008 $ 77 $ 82
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Energy Services' operating income increased $26 million for the quarter
and $6 million for the nine months ended September 30, 2008 compared with the
corresponding periods in 2007. Additional information on the year-over-year
changes is as follows:
- In the third quarter of 2008, the unrealized fair value changes in our
derivative financial electricity contracts that were not designated as
hedges for accounting purposes were favourable compared with the
corresponding period in 2007 due to the impact of a net short position
combined with larger decreases in forward Alberta power prices.
Unrealized fair value changes increased energy revenues and purchases
by $32 million and $7 million respectively, in the third quarter of
2008 compared with the third quarter of 2007.
In the nine month periods, the unrealized fair value changes in our
derivative financial electricity contracts were unfavourable in 2008
compared with the prior year due to the impact of a greater increase
in forward Alberta power prices in the first two quarters on a net
short position. Unrealized fair value changes for electricity and
natural gas derivative contracts and natural gas inventory reduced
energy revenues by $17 million and energy purchases by $5 million in
the first nine months of 2008 compared with the corresponding period
in the prior year.
Fair value reductions on a net short position of derivative financial
electricity contracts are not necessarily indicative of economic
performance as EPCOR's overall position for both physical and
derivative financial electricity contracts, including hedges, was long
and we therefore benefited economically when power prices increased.
- In the third quarter of 2008, Alberta electricity margins were lower
than in the corresponding period of 2007 primarily due to lower
generation under an intercompany contract between Generation and
Energy Services for the Joffre plant and lower ancillary services
revenue for the Joffre plant as a result of plant outages. In
addition, margins from our acquired PPAs were lower primarily due to
lower pricing for penalty payments received from the plant owners
under the terms of the PPAs. Merchant trading margins were higher in
the third quarter of 2008 primarily due to a shorter position in the
portfolio of derivative financial contracts and lower Alberta power
prices compared with the prior year.
In the nine months ended September 30, 2008 Alberta electricity
margins increased compared with the corresponding period in 2007
primarily due to increased length in the portfolio of derivative
financial contracts that settled at higher Alberta power prices. The
increase was partly offset by the impact of lower generation from
Joffre and Genesee 3 under intercompany contracts between Generation
and Energy Services, and lower margins from our acquired PPAs
primarily due to higher pricing for incentive payments paid to the
plant owners under the terms of the PPAs.
- In the third quarter of 2008, Energy Services' revenues and expenses,
excluding unrealized fair value changes, decreased $23 million and $24
million respectively, compared with the corresponding period in 2007.
The decrease in revenue was primarily due to lower physical natural
gas trading, lower generation from Joffre, decreased trading activity
in the western U.S. and lower sales to RRT customers, partly offset by
increased trading activities in the north eastern U.S. and Ontario.
The decrease in expenses was primarily due to lower physical natural
gas trading and lower Alberta power prices, partly offset by increased
trading activities in the north eastern U.S. and Ontario and lower
pricing for penalty payments received from our acquired PPA plant
owners.
Energy Services' revenues and expenses, excluding unrealized fair
value changes, decreased $39 million and $57 million, respectively in
the nine months ended September 30, 2008 compared with the
corresponding period in 2007. The decrease in revenues was primarily
due to lower physical natural gas trading activities and a higher
volume of derivative financial sell contracts that settled at losses
in 2008 as Alberta power prices exceeded the contracts' strike prices.
The contracts were used to hedge Alberta power price exposure on
electricity sales. The decrease in revenues was partly offset by
increased revenues from our acquired PPAs due to higher Alberta power
prices, increased revenues from our RRT customers due to higher
pricing partly offset by lower consumption, and increased trading
activities in the north eastern U.S. and Ontario. The decrease in
expenses was primarily due to lower physical natural gas trading
activities and increased volume of derivative financial buy contracts
which settled at higher prices, partly offset by increased trading
activities in the north eastern U.S. and Ontario and higher acquired
PPA incentive payments paid to the plant owners as a result of higher
power prices.
Water Services
-------------------------------------------------------------------------
Water Services results (including intersegment transactions)
Three months ended Nine months ended
(Unaudited, $ millions) September 30 September 30
-------------------------------------------------------------------------
2008 2007 2008 2007
Revenues $ 98 $ 70 $ 226 $ 174
Expenses 76 47 178 128
-------------------------------------------------------------------------
Operating income $ 22 $ 23 $ 48 $ 46
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Water Services' revenues from water sales were $3 and $12 million higher
in the three and nine months ended September 30, 2008 respectively, compared
with the corresponding periods in the prior year primarily due to increased
rates effective April 1, 2007 and April 1, 2008. The water rate increases
include rate adjustments associated with costs for the E.L. Smith water
treatment plant upgrade which officially opened on June 20, 2008.
Transportation and other commercial services revenues and expenses
increased in the three and nine month periods of 2008 compared with the
corresponding periods in the prior year primarily due to new commercial
services construction projects for the City of Wetaskiwin, the Towns of Taber
and Chestermere and Suncor Voyageur Energy. Maintenance expenses also
increased, primarily due to a higher incidence of water main breaks and
additional reservoir maintenance.
CONSOLIDATED BALANCE SHEETS
-------------------------------------------------------------------------
September December Increase
($ millions) 30, 2008 31, 2007 (decrease) Explanation
-------------------------------------------------------------------------
Cash and cash $ 146 $ 79 $ 67 Refer to liquidity and
equivalents capital resources
section.
-------------------------------------------------------------------------
Accounts 478 591 (113) Two months of Alberta
receivable wholesale electricity
(including settlements and Genesee
income taxes generation revenues at
recoverable) December 31, 2007
compared with one month
at September 30, 2008.
December balance also
reflects excess sinking
fund earnings received
from The City of
Edmonton in the first
quarter of 2008.
-------------------------------------------------------------------------
Derivative 123 104 19 Increase in fair value
instruments of natural gas
assets (current) derivative contracts
acquired in 2008.
-------------------------------------------------------------------------
Other current 95 74 21 Addition of natural gas
assets inventory held for
trading and normal
increase in prepaid
property taxes and
insurance at mid year.
-------------------------------------------------------------------------
Property, plant 4,517 4,216 301 2008 capital
and equipment expenditures partly
offset by depreciation
and amortization
expense.
-------------------------------------------------------------------------
Power purchase 618 679 (61) Sale of 10% interest in
arrangements Battle River PSA and
(PPAs) ongoing amortization of
remaining PPAs in 2008.
-------------------------------------------------------------------------
Contract and 173 179 (6)
customer rights
and other
intangible assets
-------------------------------------------------------------------------
Derivative 89 116 (27) Decrease in fair value
instruments assets of power and natural gas
(non-current) derivative contracts and
foreign currency forward
contracts, partly offset
by increase in fair
value of natural gas
supply contracts.
-------------------------------------------------------------------------
Future income tax 109 103 6
assets (non-current)
-------------------------------------------------------------------------
Goodwill 185 185 -
-------------------------------------------------------------------------
Other assets 257 236 21 Increase in rights to
Keephills 3 mining
asset, in net investment
in lease and in long-
term receivables
associated with the
Water Services
construction projects,
partly offset by a
reduction in fair value
of ABCP.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
September December Increase
($ millions) 30, 2008 31, 2007 (decrease) Explanation
-------------------------------------------------------------------------
Short-term debt $ 236 $ 138 $ 98 Commercial paper and
bankers acceptances
issued in 2008.
-------------------------------------------------------------------------
Accounts payable 519 615 (96) Two months of Alberta
and accrued wholesale electricity
liabilities settlements at December
31, 2007 compared with
one month at September
30, 2008, and lower
payables and accruals
for natural gas,
merchant and Water
Services capital
projects at
September 30.
-------------------------------------------------------------------------
Derivative 111 136 (25) Settlement in 2008, of
instruments power derivative
liabilities contracts held at
(current) December 31, 2007,
partly offset by
increase in fair value
of natural gas
derivative sell
contracts acquired in
2008.
-------------------------------------------------------------------------
Other current 76 98 (22) Payment of income taxes
liabilities related to the 2006
Battle River PPA gain on
sale, partly offset by
increased current future
income tax liabilities.
-------------------------------------------------------------------------
Long-term debt 2,416 2,139 277 Medium-term note
(including debentures issued in
current portion) January and April 2008
and draws on credit
facilities in the third
quarter, partly offset
by ongoing debt
repayments to The City
of Edmonton, repayment
of debt issued under
credit facilities and
repayment of a medium
term note.
-------------------------------------------------------------------------
Derivative 65 78 (13) Decrease in fair value
instruments of power and natural gas
liabilities derivative buy
(non-current) contracts.
-------------------------------------------------------------------------
Other non-current 128 125 3
liabilities
-------------------------------------------------------------------------
Future income tax 121 126 (5)
liabilities
(non-current)
-------------------------------------------------------------------------
Non-controlling 664 740 (76) Non-controlling
interests interests' share of
Power LP distributions
and net loss.
-------------------------------------------------------------------------
Shareholder's 2,454 2,367 87 Net income and other
equity comprehensive income,
partly offset by common
share dividends and
refundable income taxes.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------------------------------------------------
Cash inflows (outflows)
-------------------------------------------------------------------------
Three months ended
September 30
------------------- Increase
($ millions) 2008 2007 (decrease) Explanation
-------------------------------------------------------------------------
Operating $ 139 $ 149 $ (10) Higher payments for
interest and major
maintenance for Genesee
outages in 2008, two
months of sales receipts
for the Oxnard plant in
2008 compared with three
months of receipts in
2007 and a turbine
milestone payment at the
Frederickson plant,
partly offset by receipt
of higher Genesee PPA
availability incentives
in 2008 and realized
losses on forward
foreign exchange and
interest rate contracts
in 2007.
Investing (165) (202) 37 Purchase of ABCP in 2007
and proceeds on sale of
portfolio investments in
2008, partly offset by
higher capital
expenditures in 2008,
primarily Keephills 3,
Clover Bar Energy Centre
and DESS projects.
Financing 45 10 35 Net financing receipts
in 2008 included the
issuance of commercial
paper, partly offset by
long-term debt
repayments. Net
financing receipts in
2007 included Power LP's
private placement of
senior unsecured notes,
partly offset by
repayment of Power LP's
borrowing under its
bridge acquisition
credit facility and
Power LP's capital lease
obligation.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended
September 30
-------------------- Increase
($ millions) 2008 2007 (decrease) Explanation
-------------------------------------------------------------------------
Operating $ 278 $ 368 $ (90) Payment of Genesee PPA
availability penalties
in 2008 compared with
the receipt of
availability incentive
income in 2007, payment
in 2008 of income taxes
related to the 2006 gain
on sale of the Battle
River PPA and payments
for major maintenance
for Genesee turnarounds
in 2008, partly offset
by losses on forward
foreign exchange and
interest rate contracts
realized in 2007.
Investing (386) (332) (54) Higher capital
expenditures in 2008,
primarily Keephills 3,
Clover Bar Energy Centre
and DESS projects,
partly offset by
proceeds on sale of
portfolio investments in
2008 and purchase of
ABCP in 2007.
Financing 176 (190) 366 Net financing receipts
in 2008 included the
issuance of $600 million
of medium-term note
debentures and $98
million of commercial
paper, partly offset by
long-term debt
repayments. Net
financing outlays in
2007 included repayment
of Power LP's borrowing
under its bridge
acquisition credit
facility and Power LP's
capital lease
obligation, partly
offset by Power LP's
private placement of
senior unsecured notes
and issuance of
preferred shares by a
Power LP subsidiary.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Company's non-cash operating working capital increased $13 million
and $38 million in the three and nine months ended September 30, 2008
respectively, compared with the corresponding periods in 2007. Over the next
few quarters, we anticipate working capital requirements to fluctuate due to
normal seasonal changes in operating cash flows and the effects of plant
outages, scheduled or otherwise, including an unplanned outage at Genesee 3
(explained under Outlook below) in the fourth quarter of 2008. No significant
increases in working capital requirements are expected over the long term for
existing operations. The capital requirements to finance the Company's capital
expenditure program are expected to continue at the current pace for at least
the next two years. The Company will finance its working capital requirements
with existing credit facilities. At September 30, 2008, the Company had
undrawn and committed bank credit facilities of $1,322 million, of which $771
million is committed for at least two years.
The Company has a Canadian shelf prospectus under which it may raise up
to $1 billion of debt with maturities of not less than one year. The shelf
prospectus expires in November 2009. At September 30, 2008, the available
amount remaining under this shelf prospectus was $400 million. In addition,
Power LP has a Canadian universal shelf prospectus which expires in August
2010 under which Power LP may raise up to $1 billion in partnership units or
debt with a maximum debt amount of $600 million. At September 30, 2008, Power
LP had not drawn on the shelf prospectus and if Power LP requires major
investments of capital it may obtain new capital from external markets at the
time of the required investment.
Power LP plans to invest up to US$80 million in 2008 and 2009 for the
enhancement of the Southport and Roxboro coal plants to reduce environmental
emissions and improve their economic performance. Power LP plans to finance
this spending as well as its Morris acquisition (as discussed under
Significant Events), with existing credit facilities; with permanent financing
to be arranged following completion of the transactions, depending on the
requirements of Power LP.
At September 30, 2008, the Company had letters of credit of $221 million
(December 31, 2007 - $357 million) outstanding to meet the credit requirements
of energy market participants and conditions of certain service agreements,
and satisfy legislated reclamation requirements.
Financial market liquidity
Turmoil in the Canadian and U.S. financial markets may adversely impact
the Company's access to capital markets. Despite the ABCP liquidity issues
discussed under Significant Events, the Company has a solid contractual
liquidity position. The Company has undrawn committed credit facilities of
$1,322 million, the majority of which are with Canadian tier 1 banks, and its
debt maturing within one year is limited to $73 million of long-term debt and
$236 million of short-term commercial paper. Power market liquidity is also
impacted by the current financial market turmoil. With the withdrawal of two
major financial counterparties from the energy trading market and various
companies being less active in energy commodity trading, liquidity is a
concern and as such it is expected to take longer to enter and exit commodity
positions.
We continue to monitor changes in counterparty credit quality.
Counterparties to the PPAs, independent system operators, power and steam
sales contracts, energy supply agreements and wholesale and merchant trading
are primarily investment grade.
The Company does not have any material direct exposure to international
banking and insurance company failures.
If the world-wide credit and financial crisis continues, particularly as
it relates to Canada and the U.S., it may adversely affect the Company's
ability to draw on its existing credit facilities or arrange long-term
financing for its capital expenditure programs and acquisitions, and to
refinance outstanding indebtedness on its maturity dates. Furthermore, these
conditions have resulted in an increase in interest rate spreads and a decline
in equity markets in general, including the market price of Power LP's
partnership units, making debt financing and LP equity financing more
expensive, which may make finding accretive acquisitions more difficult for
EPCOR and Power LP.
CONTRACTUAL OBLIGATIONS
During the third quarter, the Company drew $20 million on its $490
million of two-year extendible credit facilities and $10 million on its $400
million five-year extendible syndicated bank credit facility and Power LP drew
$17 million on its $300 million of three-year revolving extendible credit
facilities.
In January 2008, the Company repaid $155 million of long-term debt
outstanding under a bank credit facility with proceeds from short-term
indebtedness. On January 31, 2008, the Company issued $200 million unsecured
medium-term note debentures and the proceeds were used to pay down short-term
indebtedness. In April 2008, the Company issued $400 million unsecured
medium-term note debentures. Net proceeds from these offerings were used to
repay short-term indebtedness, to repay debentures which matured in June 2008,
to fund a portion of the 2008 capital program and for general corporate
purposes.
In May 2008, the Company entered into an agreement with Suncor Energy
(Suncor) to design, build, own and operate a potable water and wastewater
treatment plant for Suncor's Voyageur project over a twenty-year term, in
return for payments totaling approximately $99 million commencing upon
completion of the design-build phase in 2009. The project will require a
capital outlay of approximately $30 million to be incurred in 2008 and 2009.
Power LP has committed up to US$80 million for the enhancement of the
Southport and Roxboro facilities, to be spent over 2008 and 2009.
On September 11, 2008, Power LP announced an agreement to acquire a 100%
interest in Morris for an aggregate purchase price of US$77 million subject to
finalizing closing adjustments, as discussed under Significant Events. Based
on a preliminary determination of the closing adjustments, the purchase price
has been updated to US$73 million.
There have been no other material changes to the Company's purchase
obligations, including payments for the next five years and thereafter, during
the first and second quarters. For further information on these obligations,
refer to the 2007 annual MD&A.
CHANGES IN ACCOUNTING STANDARDS
Accounting changes for 2008
Commencing January 1, 2008, the Company adopted new accounting standards
as issued by the Canadian Institute of Chartered Accountants (CICA) for
Capital Disclosures, Financial Instruments - Disclosures and Presentation, and
Inventories. The new accounting standards have been applied prospectively and
the comparative financial statements have not been restated.
Financial instruments - presentation and disclosures
The new accounting standards establish requirements for the reporting and
presentation of quantitative and qualitative information that is intended to
provide users of the financial statements with additional insight into the
Company's risks associated with financial instruments and how these risks are
managed. These risks include credit, liquidity and market risks. The
disclosures required under these new standards have been incorporated into the
unaudited interim consolidated financial statements and are discussed in Note
5 - Fair Value and Classification of Non-derivative Financial Assets and
Liabilities, Note 6 - Derivative Instruments and Hedge Accounting and Note 7 -
Risk Management.
Sensitivity analyses of the impact on net income of changes in the fair
value of derivative instruments for changes in their underlying risk factors,
such as natural gas prices and foreign exchange rates, are included in the
unaudited interim consolidated financial statements. Changes in the fair value
of Power LP's natural gas contracts has limited economic impact on the Company
as the majority of the gas supplied under long-term contracts is used for
power generation. Changes in the value of the foreign exchange contracts are
offset by changes in the value of expected foreign currency cash flows.
Therefore readers should be cautious in assessing the disclosed sensitivities.
Capital disclosures
The new accounting standard requires qualitative information about the
Company's objectives, policies and processes for managing capital and
quantitative data related to the Company's capital, as discussed in Note 8 -
Capital Management of the unaudited interim consolidated financial statements.
Inventories
The new accounting standard requires the Company's inventories to be
measured at the lower of cost and net realizable value except for natural gas
inventories held for trading purposes which are measured at fair value less
costs to sell. Our adoption of the new standard did not have a material impact
on the unaudited interim consolidated financial statements. The additional
disclosures required under the new standard are included in Note 9 -
Inventories of the unaudited interim consolidated financial statements.
Future accounting changes
Rate-regulated operations
In December 2007, the CICA amended Handbook Sections 1100 - Generally
Accepted Accounting Principles and 3465 - Income Taxes, and made consequential
amendments to Accounting Guideline 19 - Disclosures by Entities Subject to
Rate Regulation. The amendments removed the temporary exemption from the
requirement to apply Section 1100 to the recognition and measurement of assets
and liabilities arising from rate regulation. They also require rate-regulated
enterprises to recognize future income taxes separately from the regulatory
asset or liability for the future recovery from or refund to customers for
those income taxes. We will assess our accounting for rate-regulated
operations in relation to these amendments but do not expect the impact to be
material. These amendments are effective January 1, 2009 and will be adopted
by the Company as of that date.
Goodwill and intangible assets
In February 2008, the CICA issued Handbook Section 3064 - Goodwill and
Intangible Assets and consequential amendments to Section 1000 - Financial
Statement Concepts. The new section establishes standards for the recognition,
measurement and disclosure of goodwill and intangible assets. The provisions
relating to the definition and initial recognition of intangible assets,
including internally generated intangible assets, are equivalent to the
corresponding provisions in International Financial Reporting Standards
(IFRS). We will review our capitalization policies and practices for
compliance with the new standard, which will determine the impact of the
amendments to the financial statements. These amendments are effective January
1, 2009 and will be adopted by the Company as of that date.
International financial reporting standards
In February 2008, the CICA confirmed that Canadian reporting issuers will
be required to report under IFRS effective January 1, 2011, including
comparative figures for the prior year.
In January 2008, we established a core team to develop a plan which will
result in the Company's first interim report for 2011 being in compliance with
IFRS.
The diagnostic phase of the project was completed in April 2008. For each
international standard, we identified the primary differences from Canadian
GAAP and made an initial assessment of the impact of the required changes for
the purpose of prioritizing and assigning resources. In making the assessment,
the number of businesses impacted, the potential magnitude of the financial
statement adjustment, the availability of policy choices, the impacts on
systems and the impacts on internal controls were all considered.
The information obtained from the diagnostic phase was used to develop a
detailed plan for convergence and implementation. The convergence and
implementation work has five key sections: Financial Statement Adjustments,
Financial Statements, Systems Updates, Policies and Internal Controls, and
Training.
Financial Statement Adjustments
Based on the results of the diagnostic phase the following standards were
identified as most likely to have a significant impact. Certain standards
which may have a significant impact and are expected to change before January
1, 2011, such as Joint Ventures, will be addressed later in the schedule
depending on the expected timing of the revised standard.
-------------------------------------------------------------------------
Planned Initial
Review by
Audit
Committee
International Financial Reporting Standard (Quarter Year)
-------------------------------------------------------------------------
IFRS 7, IAS 32, IAS 39 Financial Instruments Q4 2008
IAS 23 Borrowing Costs Q4 2008
IAS 18 Revenue Q4 2008
IAS 16 Property, Plant and Equipment Q3 2009
IAS 31 Interests in Joint Ventures Q3 2009
IAS 21 The Effects of Changes in Foreign Exchange Rates Q3 2009
IFRS 3 Business Combinations Q3 2009
IAS 12 Income Taxes Q3 2009
IAS 17 Leases Q4 2009
IAS 37 Provisions, Contingent Liabilities and Contingent
Assets Q4 2010
IAS 36 Impairment of Assets Q4 2010
-------------------------------------------------------------------------
For each standard, we will determine the quantitative impacts to the
financial statements, system requirements, accounting policy decisions, and
changes to internal controls and business policies. The initial accounting
policy decisions will be brought forward to the Audit Committee for their
information as each standard is addressed. However, final accounting policy
decisions for all standards in effect at the end of 2009 will be made in the
fourth quarter of 2009, as they should not be determined in isolation of other
policy decisions. Policy decisions for any new standards or standards that are
amended in 2010 will be made in conjunction with our analysis of those
standards in 2010.
Financial Statements
There are also a number of standards which relate to financial statement
presentation. Commencing in the fourth quarter of 2008, sample financial
statements reflecting revised presentation and disclosure requirements will be
developed and brought forward to the Audit Committee for feedback.
Accordingly, the development of the financial statement presentation will
evolve throughout the project.
Systems Updates
The diagnostic phase identified two key accounting system requirements.
The system must be able to capture 2010 financial information under both the
prevailing GAAP and IFRS to allow comparative reporting in 2011, the first
year of reporting under IFRS. It must also be able to accommodate possible
changes to foreign currency translation methods, depending on how certain
foreign entities are classified under IFRS. A detailed system strategy is
being developed to address these issues and will be completed in the fourth
quarter of 2008 for implementation by the third quarter of 2009.
Policies and Internal Controls
In the determination of the financial statement adjustments, requirements
for changes to Company policies and internal controls will be identified and
documented. As there may be factors other than IFRS impacting policies and
internal controls, the formal documentation and approval of revised policies
and internal controls will not occur until the third quarter of 2010.
The impact of IFRS on certain agreements, such as debt, shareholder and
compensation agreements, has also been included in the plan. Strategies to
address these issues are being developed and will be completed by the second
quarter of 2009.
Training
The Company recognizes that training at all levels is essential to a
successful conversion and integration. Accounting staff have attended an
initial IFRS training session, and periodic sessions will occur throughout the
conversion process. The Board of Directors and Audit Committee have attended a
training session, and the Audit Committee receives regular updates on the
conversion project. Further training will occur throughout the project.
Financial Instruments
On October 24, 2008, the CICA approved amendments to the requirements for
accounting and disclosure of financial instruments. In particular, the
guidance permits, but only rarely, the reclassification of certain financial
instruments from categories that require fair value changes to be recognized
immediately in net income (such as "held for trading") to categories that do
not have that requirement. Such reclassifications would be recorded at their
estimated fair values at the time of transfer and would be subject to
impairment testing thereafter. Any subsequent increase in such reclassified
financial instruments' future estimated cash flows would not alter their
carrying amounts but would be reflected in the effective interest rate of the
instruments. In EPCOR's case, the result is that certain held for trading
instruments may be reclassified, and would not be subject to "mark to market"
accounting and the associated quarterly net income adjustments.
Apart from the above amendment, the CICA has indicated that it will be
providing further guidance on ABCP, in particular, the accounting for the ABCP
restructuring transactions.
The Company will consider the above-mentioned amendments and guidance in
the fourth quarter and will reflect changes, if any, to its accounting and
disclosure in its annual consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES
In preparing the consolidated financial statements, management
necessarily made estimates in determining transaction amounts and financial
statement balances. The following are the items for which significant
estimates were made in the consolidated financial statements: electricity
revenues, costs and unbilled consumption, fair values, allowance for doubtful
accounts, useful lives of assets, income taxes and PPA availability
incentives. For further information on the Company's accounting estimates,
refer to the 2007 annual MD&A.
RISK MANAGEMENT
This section should be read in conjunction with the Risk Management
section of the most recent annual MD&A. EPCOR faces a number of risks
including electricity price and volume risk, natural gas price and volume
risk, operational risk, government and regulatory risk, supply risk of
acquired PPAs, credit risk, environmental risk, project risk, availability of
people risk, weather risk, foreign exchange risk, conflicts of interest risk,
and general economic conditions and business environment risks. The Company
employs active programs to manage these risks.
As part of ongoing risk management practices, the Company reviews current
and proposed transactions to consider their impact on the risk profile of the
Company. Except for the risks described under Financial Market Liquidity,
there have been no material changes to the risk profile or risk management
strategies of EPCOR as described in the annual MD&A for 2007.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
During the first quarter of 2008, the Company implemented a new Human
Resources Information System which covers several aspects of human resource
management including payroll. The system and related control framework are
appropriately designed; however management is still working through
post-implementation issues typical of a new application system. There were no
other changes in the Company's internal controls over financial reporting
during the interim period ended September 30, 2008 that have materially
affected, or are reasonably likely to materially affect the Company's internal
control over financial reporting.
OUTLOOK
In the quarter ended September 30, 2008, net income before the impact of
fair value changes returned to pre-outage levels after the three major outages
in the first two quarters. We expect this to continue for the balance of the
year except for the potential impact of the following events.
On October 10, 2008, Genesee 3 (a 450MW generation plant, owned equally
with TransAlta Corporation) came off line due to a rotor blade failure and the
unit is expected to be off line until approximately the end of November 2008.
In addition to increasing Generation's maintenance expenses, the outage has
shortened our electricity portfolio. At the time the outage occurred, there
were other plant outages and derates in the Alberta power system which
resulted in increases in Alberta power prices. Higher electricity prices and
fewer trading counterparties make it more difficult to manage our electricity
portfolio. We estimate the decrease in EPCOR's net income in the fourth
quarter related to this outage to be in the range of $12 million to $18
million.
Although expenses for business development activity increased in the
quarter ended September 30, 2008, the increase was not as significant as
expected primarily due to the timing of the activities compared to plan.
Front-end engineering and design (FEED) work on an Integrated Gasification
Combined Cycle (IGCC) project reached a milestone in the third quarter when we
selected Siemens Fuel Gasification Technology GmbH & Co. KG as the technology
provider for the design of the coal gasification facility. EPCOR is conducting
this project in partnership with the Alberta Energy Research Institute and
Natural Resources Canada and the FEED work is a three year initiative. We
expect business development expenses for this and other initiatives to
increase in the fourth quarter.
We do not expect material expenditures for the Dodds-Roundhill project in
the fourth quarter as the Company has halted work on this project pending
analysis by Sherritt International Corporation (Sherritt). In November 2007,
EPCOR entered into a memorandum of understanding with the Carbon Development
Partnership (CDP), a general partnership indirectly and equally held by
Sherritt and the Ontario Teachers' Pension Plan that could see EPCOR
construct, own and operate facilities to provide power generation, water and
wastewater treatment services to CDP's Dodds-Roundhill coal gasification
project. We previously anticipated the power facility to be in operation by
2013, which is now not realistic and we no longer have an expected timing for
the commencement of operations.
Power LP's acquisition of Morris, as described under Significant Events,
closed on October 31, 2008 and is expected to be moderately accretive to Power
LP's cash flow. Power LP is evaluating alternatives to improve future cash
flows from the investment by leveraging Power LP's operating expertise and
pursuing growth opportunities within the geographic area of the Morris
facility.
During September and October 2008, the City of Edmonton (City) conducted
a review of the feasibility of transferring the City's Gold Bar Wastewater
Treatment Plant to EPCOR. The review related to the associated capital assets
and operations, but not the drainage operations which will remain with the
City. A report on the review was presented to Edmonton City Council on October
29, 2008, at which time City Council directed that a public hearing into the
transfer be held in the first quarter of 2009.
On September 24, 2008, Power LP announced that it was undertaking a sale
process that could lead to the sale of its 15.4% interest in Primary Energy
Recycling Holdings. If the sale proceeds, it is not anticipated to have a
material impact on the Company's net income.
FORWARD-LOOKING INFORMATION
Certain information in this MD&A is forward-looking within the meaning of
Canadian securities laws as it is related to anticipated financial
performance, events or strategies. When used in this context, words such as
"will", "anticipate", "believe", "plan", "intend", "target", and "expect" or
similar words suggest future outcomes.
Forward-looking information in this MD&A includes: (i) the purchase of a
100% equity interest in Morris by Power LP will be financed by existing credit
facilities and is expected to be moderately accretive to Power LP's cash flow;
(ii) affected ABCP will be converted into term floating-rate notes; (iii) the
breakdown of the ABCP term floating-rate notes and the expected lives of the
assets underlying these notes; (iv) the Company expects to be paid the
accumulated accrued interest on its existing ABCP from the date of the
standstill to the date of the restructuring; (v) the ABCP restructuring is
expected to be completed by the end of November 2008; (vi) the Company does
not expect there will be a material adverse impact on its business as a result
of the current ABCP liquidity issue; (vii) Keephills 3 construction will be
complete by the end of the first quarter of 2011; (viii) a potential 10%
increase in the final cost of Keephills 3 should the cost of labour in Alberta
continue to increase; (ix) construction of the remaining two Clover Bar Energy
Centre units will be complete in 2010 and the entire Clover Bar Energy Centre
project will cost an estimated $284 million; (*) expected approval of
Distribution and Transmission NSA in the fourth quarter of 2008; (xi)
anticipated fluctuations in working capital requirements over the next few
quarters due to normal seasonal changes in operating cash flows and the
effects of plant outages; (xii) the expectation of no significant increases in
working capital requirements over the long term for existing operations;
(xiii) the expectation that capital requirements to finance the Company's
capital expenditure program will continue at the current pace for at least the
next couple of years; (xiv) the expectation that the Company will finance its
working capital requirements with existing credit facilities; (xv) planned
capital upgrades at the Southport and Roxboro facilities of US$80 million;
(xvi) the expectation that Power LP will arrange permanent long-term financing
for the Morris acquisition and capital expenditures for the Southport and
Roxboro facilities; (xvii) it is expected to take longer to enter and exit
commodity positions due to liquidity concerns in the power market; (xviii) the
Company expects to receive $99 million in payments over a 20-year period from
Suncor Energy for the design, construction and operation of a potable water
and wastewater treatment plant beginning in 2009 upon completion of the
design-build phase of the project; (xix) the expectation of a $30 million
capital outlay in 2008 and 2009 for the Suncor Voyageur project; (xx)
amendments to Section 1100 of the CICA handbook for rate-regulated operations
will not have a material impact on the Company; (xxi) the IFRS plan will
proceed as disclosed on pages 22 to 24 of this MD&A and the disclosed
standards are those that will have the greatest impact on financial results;
(xxii) the Company will consider and may adopt amendments to accounting
standards on financial instruments in the fourth quarter; (xxiii) Genesee 3 is
expected to be off line until approximately the end of November 2008, which is
expected to decrease net income in the fourth quarter of 2008 by $12 million
to $18 million; (xxiv) the expectation that business development costs will
increase in the fourth quarter of 2008; (xxv) the expectation of no material
expenditures for the Dodds-Roundhill project in the fourth quarter of 2008;
and (xxvi) the possible sale of Power LP's interest in Primary Energy
Recycling Holdings is not expected to have a material impact on the Company's
net income.
These statements are based on certain assumptions and analysis made by
the Company in light of its experience and perception of historical trends,
current conditions and expected future developments and other factors it
believes are appropriate. The material factors and assumptions underlying this
forward-looking information include, but are not limited to: (i) the operation
of the Company's facilities; (ii) power plant availability, including those
subject to acquired PPAs (iii) the Company's assessment of commodity and power
markets; (iv) the Company's assessment of the markets and regulatory
environments in which it operates; (v) weather; (vi) availability of labour
and management resources; (vii) performance of contractors and suppliers;
(viii) availability and cost of financing; (ix) foreign exchange rates; (*)
management's analysis of applicable tax legislation; (xi) the currently
applicable and proposed tax laws will not change and will be implemented;
(xii) proposed environmental regulations will be implemented; (xiii)
counterparties will perform their obligations; (xiv) expected ABCP interest
rates, related credit spreads and mortality rates; (xv) Power LP management's
analysis and due diligence of the Morris facility including the related
purchase and supply agreements; and (xvi) ability to implement strategic
initiatives which will yield the expected benefits.
Whether actual results, performance or achievements will conform to the
Company's expectations and predictions is subject to a number of known and
unknown risks and uncertainties which could cause actual results and
experience to differ materially from EPCOR's expectations. Such risks and
uncertainties include, but are not limited to risks relating to: (i) operation
of the Company's facilities (ii) power plant availability and performance;
(iii) unanticipated maintenance and other expenditures; (iv) availability and
price of energy commodities; (v) electricity load settlement; (vi) regulatory
and government decisions including changes to environmental, financial
reporting and tax legislation; (vii) weather and economic conditions; (viii)
competitive pressures; (ix) construction; (*) availability and cost of
financing; (xi) foreign exchange; (xii) availability of labour and management
resources; (xii) performance of counterparties, partners, contractors and
suppliers in fulfilling their obligations to the Company; and (xiv) ABCP
market.
This MD&A includes the following updates to previously issued
forward-looking statements: (i) the ABCP restructuring is expected to be
complete by the end of November 2008, later than previous expectations due to
delays as a result of complexities and market volatility; (ii) Distribution
and Transmission expects the AUC's approval of the NSA in the fourth quarter
of 2008, earlier than the expected timing of the AUC's decision on the rate
application of the first quarter of 2009, which was based on the expectation
of a regulatory hearing proceeding rather than a negotiated settlement; and
(iii) the commencement of operations of a power facility at Dodds-Roundhill
was previously expected to be 2013, but is not determinable at this time as
the Company has ceased work on this project pending analysis by Sherritt.
Readers are cautioned not to place undue reliance on forward-looking
statements as actual results could differ materially from the plans,
expectations, estimates or intentions expressed in the forward-looking
statements. Except as required by law, EPCOR disclaims any intention and
assumes no obligation to update any forward-looking statement even if new
information becomes available, as a result of future events or for any other
reason.
QUARTERLY RESULTS
-------------------------------------------------------------------------
Net income Net income
from from
continuing discontinued
Quarter ended Revenues operations operations Net income
-------------------------------------------------------------------------
(Unaudited, $ millions)
-------------------------------------------------------------------------
September 30, 2008 $ 967 $ 76 $ - $ 76
June 30, 2008 865 16 - 16
March 31, 2008 799 68 - 68
December 31, 2007 969 59 - 59
September 30, 2007 930 67 - 67
June 30, 2007 865 53 - 53
March 31, 2007 899 98 - 98
December 31, 2006 728 16 1 17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Events for 2008, 2007 and 2006 quarters that have significantly impacted
net income from continuing operations, net income and the comparability
between quarters are:
- June 30, 2008 second quarter results reflected maintenance costs and
Genesee PPA availability penalties resulting from major turnarounds at
all three Genesee plants partly offset by the favourable impact of
high Alberta power prices on our financial contract portfolio, and
unrealized fair value gains on Power LP's natural gas supply
contracts.
- March 31, 2008 first quarter results included a $30 million gain on
the sale of a 10% interest in the Battle River PSA, the favourable
impact of high Alberta power prices on our financial contract
portfolio which was in a net long position and unrealized fair value
gains on Power LP's natural gas supply contracts. These gains were
partly offset by maintenance costs and Genesee PPA availability
penalties resulting from a major planned outage at Genesee 1, and a
fair value reduction of ABCP.
- December 31, 2007 fourth quarter results included unrealized fair
value gains on derivative financial instruments in our Alberta
merchant and wholesale portfolio which were not designated as hedges
for accounting purposes, and unrealized fair value gains on Power LP's
natural gas supply contracts. These gains were partly offset by a
reduction in the fair value of ABCP and a future income tax charge for
the impact of future tax rate reductions which were substantively
enacted in December 2007.
- September 30, 2007 third quarter results included higher Alberta
electricity margins due to favourable settlements on financial sales
as a result of higher contract prices and lower Alberta power prices.
In addition, the results included favourable unrealized fair value
changes in financial and non-financial derivative instruments, which
were not designated as hedges for accounting purposes, in Alberta
merchant and wholesale positions due to lower forward power prices
combined with a net short position.
- June 30, 2007 second quarter results included unrealized fair value
decreases in derivative financial instruments which were not
designated as hedges for accounting purposes, resulting from
increasing forward market prices. In addition, income from Power LP
included unrealized fair value decreases for the natural gas supply
contracts resulting from decreasing forward natural gas prices and
contract price changes for the Tunis plant.
- March 31, 2007 first quarter results included a $30 million gain from
the sale of a 10% interest in the Battle River PSA, an $11 million
reduction of future income tax expense resulting from a reorganization
of two subsidiaries within the Energy Services segment, and income
from Power LP due to favourable fair value changes in the natural gas
supply contracts for its Ontario generation plants which were required
under the implementation of the new accounting standard for financial
instruments effective January 1, 2007. These gains were partly offset
by unrealized fair value decreases in derivative financial instruments
resulting from a combination of increasing volumes of financial sales
contracts not qualifying for hedge accounting and increasing Alberta
forward electricity prices.
- December 31, 2006 fourth quarter results included unrealized fair
value decreases in derivative financial instruments which were not
designated as hedges for accounting purposes, resulting from
increasing forward market prices. In addition, income from Power LP
included unrealized foreign exchange losses on the translation of U.S.
debt. These events were partly offset by increased generation from a
short-term tolling arrangement with Calpine Power Income Fund, higher
generation incentive income and realized gains on foreign currency
forward contracts.
Additional information
Additional information relating to EPCOR, including EPCOR's annual
information form, is available on SEDAR at www.sedar.com.
For further information: Media inquiries: Tim le Riche, (780) 969-8238;
Shareholder and analyst inquiries: Randy Mah, (780) 412-4297 or toll free
(866) 896-4636
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