EPCOR Announces Quarterly Results
EDMONTON, July 31 /CNW/ - EPCOR Utilities Inc. (EPCOR) today released its
quarterly results for the period ended June 30, 2008.
"The second quarter saw EPCOR reach milestones in our capital and
maintenance programs, and sustain good operating performance," said EPCOR
President and CEO Don Lowry. "In June we celebrated the opening of the
upgraded E.L. Smith water treatment plant, which has already been recognized
with two awards for environmental leadership. At the Genesee Generating
Station, EPCOR and its contractors completed sequential maintenance
turnarounds for all three power units - a first for EPCOR. Our capital program
gained momentum in the first half of 2008, with significant increases in
capital investment and construction activity for the Clover Bar Energy Centre
and Downtown Edmonton Supply and Substation projects, and for Keephills 3, in
which we are a 50% partner."
Highlights of EPCOR's financial performance:
- Cash flow from operating activities for the three months ended
June 30, 2008 was $41 million compared with $55 million for the
corresponding period in the previous year.
- Cash flow from operating activities for the six months ended June 30,
2008 was $139 million compared with $219 million for the
corresponding period in the previous year.
- Net income was $16 million on revenues of $865 million for the three
months ended June 30, 2008 compared with $53 million on revenues of
$865 million for the corresponding period in the previous year.
- Net income was $84 million on revenues of $1,664 million for the six
months ended June 30, 2008 compared with $151 million on revenues of
$1,764 million for the corresponding period in the previous year.
- Other comprehensive income was $1 million for the three months ended
June 30, 2008 compared with $20 million for the corresponding period
in the previous year.
- Other comprehensive income was $24 million for the six months ended
June 30, 2008 compared with other comprehensive loss of $3 million
for the corresponding period in the previous year.
- Investment in capital projects for the three months ended June 30,
2008 was $186 million compared with $112 million for the
corresponding period in the previous year.
- Investment in capital projects for the six months ended June 30, 2008
was $294 million compared with $187 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 Utilities Inc. builds, owns and operates power plants, electrical
transmission and distribution networks, water and wastewater treatment
facilities and infrastructure in Canada and the United States. EPCOR has been
named one of Canada's Top 100 employers for eight consecutive years, and one
of only 10 companies to be selected as Canada's Most Earth-Friendly Employers.
EPCOR is headquartered in Edmonton, Alberta. EPCOR's website is www.epcor.ca.
EPCOR Utilities Inc.
Interim Management's Discussion and Analysis
June 30, 2008
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This management's discussion and analysis (MD&A), dated July 31, 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 six months ended June 30, 2008
and 2007 and in conjunction with the audited consolidated financial statements
and MD&A for the year ended December 31, 2007. 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.
FORWARD-LOOKING STATEMENTS
Certain information in this MD&A is forward-looking and related to
anticipated financial performance, events and strategies. When used in this
context, words such as "will", "anticipate", "believe", "plan", "intend",
"target", and "expect" or similar words suggest future outcomes. By their
nature, such statements are subject to significant risks, assumptions and
uncertainties, which could cause EPCOR's actual results and experience to be
materially different than the anticipated results. Such risks, assumptions and
uncertainties include, but are not limited to, operating performance,
commodity prices and volumes, load settlement, regulatory and government
decisions including changes to environmental and tax legislation, weather and
economic conditions, competitive pressures, construction risks, availability
and cost of financing, foreign exchange risks, availability of labour and
management resources and the performance of partners, contractors and
suppliers.
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.
OVERVIEW
Despite three major turnarounds at our Genesee facilities, EPCOR
maintained good operating results for the second quarter by managing our
commodity positions well. It was a period of high power prices in Alberta and
the length in our merchant portfolio resulted in healthy contributions to our
earnings.
The turnarounds at Genesee commenced in March and were completed in June.
These turnarounds 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 increased the cost of replacement power and resulted in significant
availability penalties under the terms of the Genesee Power Purchase
Arrangement (PPA).
The E.L. Smith water treatment plant upgrade was substantially completed
in June and is now capable of serving the growing Edmonton region for the next
15 years. The first unit of the Clover Bar Energy Centre, which was
commissioned in the first quarter, contributed positively to operating
earnings in the second quarter. Construction of the remaining two Clover Bar
units, the Downtown Edmonton Supply Station and the Keephills 3 power plant
continues.
In the second quarter, we received the Alberta Utilities Commission's
decision on our 2007-2009 Regulated Rate Tariff Application for non-energy
charges. Although the approved rates were lower than interim rates, the
adjustment to earnings for prior periods was insignificant and we were able to
manage our costs to the new rates.
We successfully raised $400 million in 10 year and 30 year medium-term
note financing in April. The proceeds from these financings were used to repay
short-term and maturing long-term indebtedness, to fund a portion of the 2008
capital program and for general corporate purposes. The timing of the
restructuring of asset-backed commercial paper (ABCP) has been delayed from
our earlier estimates by motions filed with the Ontario Appeals Court for
leave to appeal the judge's ruling on the fairness of the restructuring plan.
There was no significant change in our ABCP holdings or assessment of their
fair value in the quarter. We now expect the restructuring to be completed in
the third quarter of 2008.
SIGNIFICANT EVENTS
Opening of the upgraded E.L. Smith water treatment plant
On June 20, 2008, the Company officially opened the newly upgraded
E.L. Smith water treatment plant. The upgrades, which cost approximately
$140 million, are designed to increase drinking water supply by 25% for
Edmonton and the capital region, ensuring that demand can be met until at
least 2023. The water rate increases that were previously approved by The City
of Edmonton Council for 2007 and 2008 under the performance-based rates bylaw
include costs associated with the E.L. Smith water treatment plant upgrade.
$400 million of debt offerings
On April 15, 2008, the Company completed a $375 million public offering
of unsecured medium-term note debentures consisting of issues of $200 million
and $175 million. On April 28, 2008 the Company completed an additional issue
of $25 million of unsecured medium-term note debentures. The $200 million
issue has a coupon rate of 5.80% and a maturity date of January 31, 2018. The
$175 million and $25 million issues have a coupon rate of 6.65% and a maturity
date of April 15, 2038. 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.
Asset-backed commercial paper
At June 30, 2008, the Company held $51 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
$35 billion ABCP market that has been disrupted by the significant lack of
liquidity that emerged in August 2007 and as a result, all of the Company's
ABCP matured with no payment of principal, accrued interest or roll over.
A Pan-Canadian Investors Committee (Investors Committee) comprised of a
consortium representing banks, asset providers and major investors, is
overseeing the proposed restructuring of the ABCP. In March 2008, the
Investors Committee distributed to affected ABCP investors an information
package and voting materials in respect of the restructuring. Under the
proposed restructuring, the affected ABCP would be converted into term
floating-rate notes (notes) maturing no earlier than the scheduled termination
dates of the underlying assets. The restructuring documents and subsequent
presentations and conference calls provided additional information and
clarification on the proposed restructuring. The key new information as it
relates to EPCOR is as follows:
(i) EPCOR expects its breakdown of new notes under the proposed
restructuring, based on EPCOR's original book value of the
investments, to be as follows:
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Pool Series Rating Amount
($ 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) The expected lives of the assets underlying the new notes that
EPCOR expects to receive are longer than previously forecast. 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. Our previous expectation for
these notes was seven 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 higher than originally
expected, but not material to our valuation.
(v) The 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.
On June 25, 2008, the Appeals Court reserved judgement resulting in further
extensions of the standstill. These events have delayed the timing of the
restructuring from our earlier estimates and we now expect the restructuring
will be completed in the third quarter of 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 June 30, 2008 was $51 million compared with $60 million
at December 31, 2007. The estimated fair value decreased by $9 million
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.
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 Six
months months
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Net income for the periods ended June 30, 2007 $ 53 $ 151
Higher income from Power LP 14 10
Higher Alberta energy margins 4 17
Higher water rates 3 8
Lower (higher) administration expenses, excluding
Power LP administration 2 (11)
Impact of recording a net future income tax asset
associated with the Energy Services reorganization
on January 1, 2007 1 (10)
Fair value reduction in ABCP - (9)
Higher interest expense and preferred share dividends,
excluding Power LP interest expense and preferred
share dividends (9) (7)
Maintenance expenses for Genesee outages in 2008 (11) (19)
Lower Genesee PPA availability and capacity payment
income (19) (24)
Unrealized fair value changes on derivative
instruments and natural gas inventory held for
trading (22) (21)
Other - (1)
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Decrease in net income (37) (67)
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Net income for the periods ended June 30, 2008 $ 16 $ 84
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Net income was $16 million and $84 million for the three and six months
ended June 30, 2008 respectively, compared with $53 million and $151 million
for the corresponding periods in 2007. The decreases were due to the net
impact of the following:
- Net income from EPCOR Power L.P. (Power LP) was higher primarily due
to unrealized fair value changes on natural gas supply, forward
foreign exchange and interest rate contracts. In the three months
ended June 30 these increases were partly offset by a smaller foreign
exchange gain in 2008 compared with 2007, on the translation of
United States (U.S.) debt. In the six months ended June 30, 2008,
foreign exchange losses were incurred on the translation of U.S. debt
whereas foreign exchange gains were incurred in the corresponding
period in 2007. The U.S. dollar strengthened relative to the Canadian
dollar in the first half of 2008 and weakened in the corresponding
period in 2007.
- Alberta electricity margins increased primarily due to increased
length in the portfolio of derivative financial contracts that
settled at higher Alberta 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.
- Administration expenses, excluding Power LP's administration,
increased in the first half of 2008 compared with the corresponding
period in 2007 primarily due to a reduction of the Company's
liability for its Long-Term Incentive Plan (LTIP) in the first
quarter of the prior year. A similar but smaller adjustment was
recorded in the first quarter of 2008. The LTIP is a notional stock
option plan for senior management. Adjustments were recorded based on
the results of the quarterly valuations of the plan. In addition, in
the first six months of 2008, costs for management incentive
compensation other than LTIP were higher and there were fewer staff
vacancies compared with the corresponding period in the prior year.
- 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.
- 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. 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 three and six month periods ended June 30 were more
than offset by a reduction reflecting the substantive enactment of an
income tax rate reduction attributable to preferred share dividends
paid commencing in 2003.
- Maintenance expenses for Genesee outages were higher as there were no
outages in the first half of 2007. In 2008, the Genesee 1 outage
started in the first quarter and was completed in the second quarter,
and the Genesee 2 and 3 outages occurred in the second quarter.
- A net availability penalty was incurred in the first half of 2008
under the terms of the Genesee 1 and 2 PPA compared with availability
incentive revenue recognized in the corresponding period in 2007. The
net penalty in 2008 was due to the major outages at these units.
Capacity payment revenue under this PPA was also lower as a result of
a lower return from a declining PPA rate-base and reduced tax
recoveries related to lower federal income tax rates.
- The unrealized fair value changes in our financial electricity
contracts that were not designated as hedges for accounting purposes
were unfavourable in the first half of 2008 compared with the
corresponding period in 2007 due to larger net short positions
combined with greater increases in Alberta forward power prices in
2008. The unrealized fair value changes in our natural gas portfolio
were also unfavourable due to net short positions in both years
combined with increases in forward prices in the first half of 2008
compared with decreases in forward prices in the corresponding period
in 2007. An unrealized fair value loss was recognized on the Joffre
contract-for-differences (CfD) in 2008 due to an unfavourable forward
spark spread compared with an unrealized fair value gain and
favourable forward spark spread in 2007. 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. These unfavourable changes were partly offset by
unrealized fair value gains on forward foreign exchange contracts for
U.S. dollars in the first half of 2008 compared with unrealized fair
value losses in the corresponding period in 2007.
Revenues
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(Unaudited, $ millions) Three Six
months months
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Revenues for the periods ended June 30, 2007 $ 865 $ 1,764
Higher (lower) physical natural gas trading activities 31 (59)
Higher trading activities in the north eastern U.S.
and Ontario 17 19
Higher Alberta energy revenues 4 16
Higher water rates 3 9
Higher energy revenues from trading activities in the
western U.S. 1 9
Lower Power LP revenues (17) (39)
Unrealized fair value changes on derivative
instruments and natural gas inventory held for
trading (25) (41)
Lower Genesee PPA availability and capacity payment
revenues (27) (34)
Commercial and other revenues 13 20
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Decrease in revenues - (100)
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Revenues for the periods ended June 30, 2008 $ 865 $ 1,664
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Consolidated revenues for the three months ended June 30, 2008 were
unchanged from the corresponding period in 2007, and for the six months ended
June 30, 2008 were lower than for the corresponding period in 2007. Further
information on the year over year changes is summarized as follows:
- Alberta energy revenues included higher electricity pricing for our
Regulated Rate Tariff (RRT) customers and increased revenues from the
Alberta Power Pool due to higher prices. These increases were partly
offset by derivative financial sell contracts that settled at losses
in 2008 resulting from Alberta power prices that exceeded the
contracts' strike prices.
- 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. Sales of natural gas
to utilize excess transmission capacity at the Castleton facility
were also lower.
- Unrealized fair value losses on derivative financial sell contracts
that were not designated as hedges for accounting purposes were
higher due to an increased short position and larger increases in
forward Alberta power prices.
- Commercial services and other revenues were higher primarily due to
new water and wastewater facility construction contracts with the
City of Wetaskiwin and the Towns of Taber and Chestermere and higher
transportation revenues from The City of Edmonton. Transportation
revenues were primarily derived from the construction and maintenance
of street lighting, traffic signal, light rail transit and trolley
assets owned by The City of Edmonton.
Capital spending and investment
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(Unaudited, $ millions)
Six months ended June 30 2008 2007
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Generation $ 197 $ 87
Distribution and Transmission 63 36
Energy Services 2 7
Water Services 26 49
Corporate - other 6 8
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$ 294 $ 187
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Capital expenditures for property, plant and equipment were higher for
the six months ended June 30, 2008 compared with the same period in 2007
primarily due to increased construction activity on the Keephills 3 and Clover
Bar Energy Centre generation projects and on the Downtown Edmonton Supply and
Substation (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. Construction is expected to be completed by 2011.
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.
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 is scheduled for completion in 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 is now substantially complete.
SEGMENT RESULTS
Generation
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Generation results (including
intersegment transactions) Three months ended Six months ended
(Unaudited, $ millions) June 30 June 30
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2008 2007 2008 2007
Revenues $ 234 $ 265 $ 455 $ 509
Expenses 118 212 250 329
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Operating income $ 116 $ 53 $ 205 $ 180
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(Unaudited, $ millions) Three Six
months months
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Operating income for the periods ended June 30, 2007 $ 53 $ 180
Higher Power LP operating income 106 88
Unrealized fair value changes on derivative instruments (2) 2
Increased maintenance for Genesee outages in 2008 (15) (26)
Lower Genesee PPA availability and capacity payment
revenues (27) (34)
Other 1 (5)
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Increase in operating income 63 25
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Operating income for the periods ended June 30, 2008 $ 116 $ 205
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Generation's operating income for the quarter and half year ended June 30,
2008 increased $63 million and $25 million respectively, over the
corresponding periods in 2007. Further information on the year over year
changes is as follows:
- Power LP contributed $118 million of operating income in the second
quarter and $182 million in the first six months of 2008 compared
with $12 million and $94 million respectively, for the corresponding
periods in 2007.
Power LP's revenues decreased $17 million in the second quarter and
$39 million for the first half 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.
Power LP's expenses decreased $123 million in the second quarter and
$127 million in the first half of 2008 compared with the
corresponding periods in the prior year primarily due to unrealized
gains in 2008 and unrealized losses in 2007 for changes in the fair
value of the natural gas supply contracts. The decrease in expenses
was also due to losses realized in 2007 on forward foreign exchange
and interest rate contracts that were entered into in anticipation of
permanent financing of acquisitions completed in 2006, whereas no
similar contracts were settled in 2008. The decrease in expenses was
partly offset by higher foreign exchange expense on the translation
of U.S. debt in 2008.
- Unrealized changes in the fair value of the Joffre contract-for-
differences (CfD) increased expenses and revenues in the three and
six month periods ended June 30, 2008 compared with the corresponding
periods in the prior year. The net impact of the fair value changes
on the Joffre CfD was to decrease operating income by $9 million in
the second quarter and $12 million in the first half of 2008 due to a
decrease in the forward spark spread in 2008 and an increase in 2007.
These decreases in operating income were offset by unrealized fair
value changes on forward foreign exchange contracts for U.S. dollars
entered into in anticipation of asset purchases related to the Clover
Bar Energy Centre and Keephills 3 projects, which decreased expenses
by $7 million in the three months and $14 million in the six months
ended June 30, 2008 compared with the corresponding periods in 2007.
The impact of the unrealized fair value changes for both the Joffre
CfD and the forward foreign exchange contracts was to increase
revenues and expenses by $6 million and $8 million respectively, in
the second quarter and by $8 million and $6 million respectively, in
the six months ended June 30, 2008 compared with the corresponding
periods in the prior year.
- The new Clover Bar Energy Centre turbine, included in other in the
table above, contributed $2 million in revenues and incurred
$1 million in expenses since it commenced operations in the first
quarter of 2008.
Distribution and Transmission
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Distribution and Transmission
results (including intersegment
transactions) Three months ended Six months ended
(Unaudited, $ millions) June 30 June 30
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2008 2007 2008 2007
Revenues $ 59 $ 59 $ 118 $ 118
Expenses 53 50 100 98
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Operating income $ 6 $ 9 $ 18 $ 20
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There were no material changes in Distribution and Transmission revenues,
expenses and operating income, for the three and six months ended June 30,
2008 compared with the same periods in the prior year. Distribution and
Transmission expects to receive a final decision from the Alberta Utilities
Commission on its 2007-2009 General Tariff Application in early 2009.
Energy Services
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Energy Services results
(including intersegment
transactions) Three months ended Six months ended
(Unaudited, $ millions) June 30 June 30
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2008 2007 2008 2007
Revenues $ 567 $ 544 $ 1,095 $ 1,160
Expenses 575 528 1,089 1,135
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Operating income (loss) $ (8) $ 16 $ 6 $ 25
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(Unaudited, $ millions) Three Six
months months
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Operating income for the periods
ended June 30, 2007 $ 16 $ 25
Higher Alberta electricity margins 5 23
Unrealized fair value change in natural gas inventory
held for trading 3 3
Higher energy margin from trading activities in the
north eastern U.S. and Ontario 3 3
Lower natural gas margin (1) (3)
Unrealized fair value changes in derivative instruments (35) (40)
Other 1 (5)
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Decrease in operating income (24) (19)
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Operating income (loss) for the periods ended
June 30, 2008 $ (8) $ 6
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Energy Services' operating income decreased $24 million for the quarter
and $19 million for the six months ended June 30, 2008 compared with the
corresponding periods in 2007. Additional information on the year over year
changes is as follows:
- Alberta electricity margins increased primarily due to increased
length in the portfolio of derivative financial contracts that
settled at higher Alberta power prices compared with the prior year.
The generation from our interests in the Battle River and Sundance
acquired PPAs was sold at higher prices to the Alberta Power Pool
subsequent to the expiry of a long-term sales contract with a third
party customer at the end of 2007. The impact of this favourable
pricing more than offset the impact of our reduced interest in the
Battle River PSA (Power Syndicate Agreement) following the sale on
January 15, 2008.
The increase was partly offset by the impact of lower generation from
Genesee 3 under an intercompany contract between Generation and
Energy Services, and our acquired PPAs resulting from plant outages
and incidences of reduced plant availability in the second quarter
of 2008.
- In the second quarter of 2008 Energy Services' revenues and expenses,
excluding unrealized fair value changes, increased $54 million and
$46 million respectively, compared with the corresponding period in
2007. These increases were primarily due to higher physical natural
gas revenues and expenses, $31 million and $32 million respectively,
increased trading activities in the north eastern U.S. and Ontario
and higher prices for energy sales and purchases in Alberta. In
addition, energy revenues from our RRT customers increased due to
higher pricing. These increases were partly offset by derivative
financial sell contracts that settled at losses in 2008 resulting
from Alberta power prices that exceeded the contracts' strike prices.
Energy Services' revenues and expenses, excluding unrealized fair
value changes, decreased $17 million and $34 million, respectively in
the six months ended June 30, 2008 compared with the corresponding
period in 2007. These decreases were primarily due to lower physical
natural gas trading activities in the first quarter of 2008 which
more than offset the increase in activity in the second quarter.
Natural gas sales and purchases decreased $59 million and $56 million
respectively, in the six months ended June 30, 2008 compared with the
corresponding period in 2007. In the six months ended June 30, the
lower physical gas trading activity was partly offset by the same
items identified above for the second quarter as well as increased
trading activities in the western U.S. in the first quarter.
- The unrealized fair value changes in our derivative financial
electricity contracts that were not designated as hedges for
accounting purposes were unfavourable compared with the prior year
due to the impact of a greater increase in forward Alberta power
prices on larger net short positions in the three and six month
periods ended June 30, 2008. Unrealized fair value changes reduced
energy revenues by $31 million and increased energy purchases by
$1 million in the second quarter and reduced energy revenues by
$48 million and energy purchases by $12 million in the first half of
2008. Fair value reductions on a net short position of derivative
financial contracts are not necessarily indicative of economic
performance as EPCOR's overall position for both physical and
derivative financial contracts, including hedges, was long and we
therefore benefited economically when power prices increased.
On April 30, 2008, the Alberta Utilities Commission released its decision
on the Company's 2007 - 2009 Regulated Rate Tariff Application related to its
RRT operations. The impact of the decision was recorded in the second quarter
of 2008 and did not have a material impact on Energy Services' revenues,
expenses or net income.
Water Services
-------------------------------------------------------------------------
Water Services results (including
intersegment transactions) Three months ended Six months ended
(Unaudited, $ millions) June 30 June 30
-------------------------------------------------------------------------
2008 2007 2008 2007
Revenues $ 70 $ 61 $ 128 $ 104
Expenses 55 46 102 81
-------------------------------------------------------------------------
Operating income $ 15 $ 15 $ 26 $ 23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Water Services' revenues from water sales were $3 and $9 million higher
in the three and six months ended June 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. Transportation and other commercial
services revenues and expenses were higher by $6 million and $9 million
respectively, in the second quarter and $15 million and $17 million
respectively, in the first half of 2008 compared with the corresponding
periods in the prior year. The increases were primarily due to new commercial
services construction projects for the City of Wetaskiwin and the Towns of
Taber and Chestermere and higher business development costs. Maintenance
expenses were higher in the first half of 2008 compared with the corresponding
period in 2007 primarily due to a higher incidence of water main breaks and
additional reservoir maintenance.
CONSOLIDATED BALANCE SHEETS
-------------------------------------------------------------------------
Significant changes in consolidated assets
-------------------------------------------------------------------------
June 30, December Increase
($ millions) 2008 31, 2007 (decrease) Explanation
-------------------------------------------------------------------------
Cash and cash $ 126 $ 79 $ 47 Refer to liquidity and
equivalents capital resources
section.
-------------------------------------------------------------------------
Accounts receivable 473 591 (118) Two months of Alberta
(including income wholesale electricity
taxes recoverable) settlements and Genesee
generation revenues at
December 31, 2007
compared with one month
at June 30, 2008.
December balance also
reflects excess sinking
fund earnings received
from The City of
Edmonton in the first
quarter of 2008.
-------------------------------------------------------------------------
Derivative 249 104 145 Increase in fair value
instruments of natural gas and
assets (current) power derivative
contracts due to
increased forward
prices.
-------------------------------------------------------------------------
Other current assets 100 74 26 Addition of natural gas
inventory held for
trading and normal
increase in prepaid
property taxes and
insurance at mid year.
-------------------------------------------------------------------------
Property, plant 4,405 4,216 189 2008 capital
and equipment expenditures partly
offset by depreciation
and amortization
expense.
-------------------------------------------------------------------------
Power purchase 631 679 (48) Sale of 10% interest in
arrangements (PPAs) Battle River PSA and
ongoing amortization of
remaining PPAs in 2008.
-------------------------------------------------------------------------
Contract and 175 179 (4)
customer rights
and other
intangible assets
-------------------------------------------------------------------------
Derivative 257 116 141 Increase in fair value
instruments assets of natural gas and
(non-current) power derivative
contracts due to
increases in forward
prices, partly offset
by decrease in fair
value of foreign
currency forward
contracts.
-------------------------------------------------------------------------
Future income tax 135 103 32 Change in the expected
assets (non-current) timing of the use of
tax loss carryforward
balances from current
to long-term and
increase in deductions
available for tax
purposes for unrealized
fair value changes in
derivative instruments.
-------------------------------------------------------------------------
Goodwill 185 185 -
-------------------------------------------------------------------------
Other assets 250 236 14 Increase in rights to
Keephills 3 mining
asset and in long-term
receivables associated
with the Taber,
Wetaskiwin and
Chestermere projects,
partly offset by a
reduction in fair value
of ABCP.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Significant changes in consolidated liabilities and shareholder's equity
-------------------------------------------------------------------------
June 30, December Increase
($ millions) 2008 31, 2007 (decrease) Explanation
-------------------------------------------------------------------------
Short-term debt $ 171 $ 138 $ 33 Commercial paper issued
during the first six
months of 2008.
-------------------------------------------------------------------------
Accounts payable 517 615 (98) Two months of Alberta
and accrued wholesale electricity
liabilities settlements at
December 31, 2007
compared with one month
at June 30, 2008, and
lower payables and
accruals for natural
gas, merchant and Water
Services capital
projects at June 30,
partly offset by
increased payables and
accruals for Generation
capital projects and
Genesee operations at
June 30.
-------------------------------------------------------------------------
Derivative 229 136 93 Increase in fair value
instruments of derivative natural
liabilities gas and power contracts
(current) due to increases in
forward prices.
-------------------------------------------------------------------------
Other current 86 98 (12) Reflects payment of
liabilities income taxes related to
the 2006 Battle River
PPA gain on sale,
partly offset by
increased current
future income tax
liabilities.
-------------------------------------------------------------------------
Long-term debt 2,362 2,139 223 Medium-term note
(including current debentures issued in
portion) January and April 2008,
partly offset by
ongoing debt repayments
to The City of Edmonton
and repayment of debt
issued under credit
facilities.
-------------------------------------------------------------------------
Derivative 151 78 73 Increase in fair value
instruments of derivative power
liabilities and natural gas
(non-current) contracts due to
increases in forward
prices.
-------------------------------------------------------------------------
Other non-current 121 125 (4)
liabilities
-------------------------------------------------------------------------
Future income tax 150 126 24 Increase in taxable
liabilities temporary differences
(non-current) relating to unrealized
fair value changes in
derivative instruments.
-------------------------------------------------------------------------
Non-controlling 795 740 55 Reflects non-
interests controlling interests'
share of Power LP
income less
distributions.
-------------------------------------------------------------------------
Shareholder's 2,404 2,367 37 Reflects net income
equity and other comprehensive
income, partly offset
by common share
dividends and
refundable income
taxes.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RE
SOURCES
-------------------------------------------------------------------------
Cash inflows (outflows)
-------------------------------------------------------------------------
Three months
ended June 30
---------------- Increase
($ millions) 2008 2007 (decrease) Explanation
-------------------------------------------------------------------------
Operating $ 41 $ 55 $ (14) Payment of Genesee PPA
availability penalties
in the second quarter
of 2008 compared with
receipt of incentive
income in 2007,
payments for major
maintenance for Genesee
turnarounds in 2008,
partly offset by
realized losses on
forward foreign
exchange and interest
rate contracts in 2007
and changes in non-cash
operating working
capital, primarily four
months of sales
receipts for the
Ontario plants in 2008
compared with three
months of receipts
in 2007.
Investing (146) (91) (55) Higher capital
expenditures in 2008,
primarily on the
Keephills 3, Clover Bar
Energy Centre and DESS
projects.
Financing 129 (104) 233 Net financing receipts
in 2008 included the
issuance of
$400 million of medium-
term note debentures,
partly offset by long-
term debt repayments.
Net financing outlays
in 2007 included
repayment of Power LP's
borrowing under its
bridge acquisition
credit facility, partly
offset by the issuance
of preferred shares by
a subsidiary.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash inflows (outflows)
-------------------------------------------------------------------------
Six months
ended June 30
---------------- Increase
($ millions) 2008 2007 (decrease) Explanation
-------------------------------------------------------------------------
Operating $ 139 $ 219 $ (80) Payment of Genesee PPA
availability penalties
in 2008 compared with
the receipt of
availability incentive
income 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 (221) (130) (91) Reflects higher capital
expenditures, primarily
on the Keephills 3,
Clover Bar Energy
Centre and DESS
projects.
Financing 131 (200) 331 Net financing receipts
in 2008 included the
issuance of
$600 million of medium-
term note debentures
and $32 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, partly
offset by the issuance
of preferred shares by
a subsidiary.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At June 30, 2008 the Company had letters of credit outstanding of
$219 million (December 31, 2007 - $357 million) to meet the credit
requirements of energy market participants, to meet conditions of certain debt
and service agreements, and to satisfy legislated reclamation requirements.
CONTRACTUAL OBLIGATIONS
In January 2008, the Company repaid its $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 as described under Significant Events. 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.
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 separate 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 April 2008, the CICA released an
exposure draft of the coming standards. We have developed a high level IFRS
implementation plan, and an assessment of the impact of the accounting
standard differences to the financial statements is currently in progress.
Based on our analysis to date, the most significant differences for EPCOR are
anticipated to be related to property, plant and equipment, joint
arrangements, business combinations, emission credits, asset retirement
obligations and financial statement disclosure. We also expect to make changes
to certain processes and systems before 2010 to ensure transactions are
recorded in accordance with IFRS for comparative reporting purposes on the
required implementation date. We will report on the key elements and timing of
our IFRS implementation plan in our interim MD&A for the third quarter of
2008.
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. 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 June 30, 2008 that have materially affected, or are
reasonably likely to materially affect the Company's internal control over
financial reporting.
OUTLOOK
With the major outages at Genesee now complete, net income before the
impact of fair value changes is expected to return to pre-outage levels. The
major outages at Genesee combined with the high Alberta power prices in the
second quarter resulted in higher Genesee PPA availability penalties and
higher major maintenance costs than anticipated. For the balance of the year
we expect higher generation from Genesee 3, reduced Genesee availability
penalties and lower Generation maintenance costs compared to the first half of
the year. However, we expect increased costs for business development activity
related to water and power initiatives. On July 8, 2008 we disposed of an
equity investment and recognized a $9 million pre-tax gain in net income which
was previously recorded as a fair value change in accumulated other
comprehensive income.
QUARTERLY RESULTS
Net income Net income
from (loss) from
continuing discontinued
Quarter ended Revenues operations operations Net income
-------------------------------------------------------------------------
(Unaudited, $ millions)
-------------------------------------------------------------------------
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
September 30, 2006 702 47 9 56
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Events for 2008, 2007 and 2006 quarters that have significantly impacted
net income from continuing operations, net income and the comparability
between quarters are:
- March 31, 2008 first quarter results included a $30 million gain on
the sale of a 10% interest in the Battle River PSA and the favourable
impact of high Alberta power prices on our financial contract
portfolio which was in a net long position. 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.
- September 30, 2006 third quarter results included an increase in net
income from discontinued operations of $10 million for the reduction
of the Clover Bar asset retirement obligation offset by reduced
Alberta electricity margins from the Battle River and Sundance PPAs
resulting from the sale of partial interests in these agreements in
the second quarter of 2006.
Additional information
Additional information relating to EPCOR, including EPCOR's annual
information form, is available on SEDAR at www.sedar.com.
For further information:
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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