EPCOR Power L.P. reports third quarter results
Third quarter revenue was
"Performance at our facilities was mixed in the third quarter of 2009," said
"The Partnership remains committed to the diversification of our portfolio, both in terms of geography and fuel type, as one of the cornerstones of our strategy," added
On
Also on
Highlights of EPCOR Power L.P.'s operational and financial performance included:
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Operational and Financial Three months ended Nine months ended
Highlights (unaudited) September 30 September 30
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(millions of dollars except
per unit and operational
amounts) 2009 2008 2009 2008
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Power generated (GWh) 1,228 1,247 2,331 2,319
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Weighted average plant
availability 93% 95% 92% 92%
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Revenue 155.5 133.5 292.8 262.0
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Cash provided by operating
activities of continuing
operations 33.8 20.0 100.6 101.0
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Per unit(1) $0.63 $0.37 $1.87 $1.87
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Cash distributions 23.7 34.0 81.4 101.9
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Per unit $0.44 $0.63 $1.51 $1.89
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Payout ratio(2) 71% 89% 89% 107%
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Capital expenditures 33.0 5.1 75.9 18.5
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Weighted average units
outstanding (millions) 53.9 53.9 53.9 53.9
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(1) Cash provided by operating activities of continuing operations per
unit is a non-GAAP financial measure that is defined in the interim
MD&A.
(2) Payout ratio is cash distributions divided by cash provided by
operating activities of continuing operations excluding working
capital changes less maintenance capital expenditures.
The
EPCOR Power L.P.
Management's Discussion and Analysis
For the Nine Months Ended September 30, 2009
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This management's discussion and analysis (MD&A) is dated
On
The General Partner is responsible for management of the Partnership. The Board of Directors (the Board) of the General Partner declares the cash distributions to the Partnership's unitholders. The General Partner has engaged CP Regional Power Services Limited Partnership and Capital Power Operations (USA) Inc., both subsidiaries controlled by CPC (collectively herein, the Manager), to perform management and administrative services for the Partnership and to operate and maintain the power plants pursuant to management and operations agreements. The Audit Committee of the Board is to review and approve the interim MD&A of the Partnership in accordance with the Audit Committee's terms of reference. The Audit Committee has reviewed and approved the contents of this interim MD&A.
SIGNIFICANT EVENTS
Change to monthly distributions and launch of distribution reinvestment
plan
On
Preferred share offering
On
CONSOLIDATED RESULTS OF OPERATIONS
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Three Nine
(millions of dollars)(unaudited) months months
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Cash provided by operating activities of continuing
operations for the three and nine months ended
September 30, 2008 20.0 101.0
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Changes in operating working capital 17.9 1.8
Contribution of Morris acquired October 31, 2008,
excluding interest paid 5.6 11.3
Higher operating margin at the Northwest US plants 4.2 5.4
Lower management and administration costs 1.0 2.3
Higher operating margin at Curtis Palmer 0.8 4.5
Lower operating margin at the Ontario plants (10.3) (14.5)
Lower operating margin at the North Carolina plants (2.4) (8.9)
Higher interest expenses (1.0) (4.2)
Other (2.0) 1.9
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Cash provided by operating activities of continuing
operations for the three and nine months ended
September 30, 2009 33.8 100.6
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The Partnership reported cash provided by operating activities of continuing operations of
- An increase in working capital of $3.5 million in the three months
ended September 30, 2009 compared to $21.4 million during the same
period in the prior year. Working capital increased in 2009 primarily
due to the timing of payments and receipts;
- The Morris facility, which was acquired on October 31, 2008, provided
$5.6 million of operating margin;
- Operating margin was $4.2 million higher at the Northwest US plants
due to the payment of a non-recurring milestone payment by
Frederickson under its long-term service agreement with the turbine
manufacturer in the third quarter of 2008;
- Administrative costs were $1.0 million lower primarily due to lower
incentive fees as a result of changes in the method of determining
the incentive fees; and
- Operating margin was $0.8 million higher at Curtis Palmer due to a
step-up in pricing under the power purchase arrangement (PPA) of 18%
in December 2008 and higher generation due to higher water flows.
Increases were partially offset by the following:
- Operating margin was $10.3 million lower at the Ontario plants
primarily due to lower natural gas prices, a $3.4 million reduction
of natural gas costs recorded in 2008 as the Partnership updated its
estimate of the cost for natural gas supplied under contract, an
unplanned outage at Calstock, lower power demand in Ontario and lower
revenues from waste heat;
- Operating margin was $2.4 million lower at the North Carolina plants
due to higher maintenance costs and lower generation due to lower
natural gas prices resulting in increased competition from natural
gas plants in the region; and
- Higher interest expenses of $1.0 million were incurred due to
interest on draws under the Partnership's revolving credit facilities
to finance the acquisition of the Morris facility.
The Partnership reported cash provided by operating activities of continuing operations of
- Higher interest expenses of $4.2 million were incurred due to the
impact of a stronger US dollar relative to the Canadian dollar on
US dollar interest expenses and interest on draws under the
Partnership's revolving credit facilities to finance the acquisition
of the Morris facility.
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Three Nine
(millions of dollars)(unaudited) months months
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Cash provided by operating activities for the three
and nine months ended September 30, 2008 21.5 104.8
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Increase (decrease) in cash provided by operating
activities of continuing operations - see previous
table 13.8 (0.4)
Decrease in cash provided by operating activities
of discontinued operations (1.5) (6.6)
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Cash provided by operating activities for the three
and nine months ended September 30, 2009 33.8 97.8
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The Partnership reported cash provided by operating activities of
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Three Nine
(millions of dollars)(unaudited) months months
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Net (loss) income from continuing operations for
the three and nine months ended September 30, 2008 (152.2) 6.2
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Fair value changes on natural gas supply and foreign
exchange contracts 187.6 11.5
Foreign exchange losses in 2008 15.9 26.4
Contribution of Morris acquired October 31, 2008,
excluding interest paid 5.6 11.3
Higher operating margin at the Northwest US plants 4.2 5.4
Lower management and administration costs 1.0 2.3
Higher operating margin at Curtis Palmer 0.8 4.5
Increase (decrease) in income tax recovery (17.9) 3.9
Lower operating margin at the Ontario plants (10.3) (14.5)
Lower operating margin at the North Carolina plants (2.4) (8.9)
Higher interest expenses (1.0) (4.2)
Higher depreciation and amortization mainly due to
the Morris acquisition in 2008 (0.1) (3.4)
Other (0.5) (0.1)
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Net income from continuing operations for the three
and nine months ended September 30, 2009 30.7 40.4
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Net income from continuing operations was
- Net gains of $12.5 million were recorded in the third quarter of 2009
on changes in the fair value of the natural gas supply and foreign
exchange contracts compared to a net losses of $175.1 million in the
third quarter of 2008. The majority of the changes in fair value are
the result of a strengthening of future prices for the Canadian
dollar relative to the US dollar in the third quarter of 2009
compared to decreases in the future prices for natural gas in the
third quarter of 2008; and
- In the fourth quarter of 2008, the Partnership re-evaluated the
functional currency of its US subsidiaries and determined it to be
US dollars. Accordingly, gains and losses on foreign currency
translation are accumulated as a component of partners' equity
commencing in the fourth quarter of 2008. The Partnership reported
net foreign exchange losses of $15.8 million for the three months
ended September 30, 2008.
Increases were partially offset by the following:
- An income tax recovery of $4.2 million was recorded in the third
quarter of 2009 compared to $22.1 million in 2008. The change was
mainly due to future income taxes on changes in temporary differences
primarily related to changes in the fair value of natural gas and
foreign exchange contracts.
Net income from continuing operations was $40.4 million or $0.75 per unit
for the nine months ended September 30, 2009 compared with $6.2 million or
$0.12 per unit for the same period in 2008. The $34.2 million increase in net
income from continuing operations for the nine months ended September 30, 2009
compared to the same period in 2008 is primarily due to the items described
above for the current quarter, as well as the following:
- Net losses of $2.5 million were recorded in the nine months ended
September 30, 2009 on the change in the fair value of the natural gas
supply and foreign exchange contracts compared to $14.1 million in
the same period in 2008. The majority of the changes in fair value
are the result of decreases in future prices for natural gas
partially offset by a strengthening of future prices for the Canadian
dollar relative to the US dollar in the nine months ended September
30, 2009 compared to a weakening of future prices for the Canadian
dollar relative to the US dollar in the same period in 2008.
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Three Nine
(millions of dollars)(unaudited) months months
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Net (loss) income for the three and nine months
ended September 30, 2008 (153.0) 5.3
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Increases in the net income from continuing
operations - see previous table 182.9 34.2
Increase in net income from discontinued operations 0.8 0.7
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Net income for the three and nine months ended
September 30, 2009 30.7 40.2
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NON-GAAP MEASURES
The Partnership uses operating margin as a performance measure and cash provided by operating activities of continuing operations per unit as a cash flow measure. These terms are not defined financial measures according to Canadian generally accepted accounting principles (GAAP) and do not have standardized meanings prescribed by GAAP. Therefore, these measures may not be comparable to similar measures presented by other enterprises.
The Partnership uses operating margin to measure the financial performance of plants and groups of plants. A reconciliation from operating margin to net income from continuing operations before tax and preferred share dividends is as follows:
Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
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Operating margin 65.9 (118.4) 152.8 143.5
Deduct:
Depreciation and amortization 22.9 22.8 70.0 66.6
Management and administration 3.7 4.7 10.9 13.2
Foreign exchange losses 0.1 15.9 0.7 26.4
Equity losses in PERH 0.8 1.7 3.1 3.8
Financial charges and other, net 10.2 9.2 31.6 27.4
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Net income (loss) from continuing
operations before tax and
preferred share dividends 28.2 (172.7) 36.5 6.1
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Cash provided by operating activities of continuing operations per unit is cash provided by operating activities of continuing operations (a GAAP defined measure) divided by the weighted average number of units outstanding in the period. The composition of these measures is consistent with
CHANGES IN ACCOUNTING POLICIES
Commencing
Credit risk and the fair value of financial assets and financial
liabilities
On
Increase
Balance sheet item (decrease) Explanation
------------------------------- ------------ --------------------------
Derivative instruments assets (1.5) Impact to fair value of
foreign exchange and
natural gas contracts
from incorporating credit
Derivative instruments risk of counterparties of
liabilities (6.3) the Partnership.
Future income taxes liabilities
- non-current 0.9 Tax impact from adoption
of new standard.
Opening deficit (3.9) After tax impact to
opening deficit resulting
from adoption of new
standard.
------------------------------- ------------ --------------------------
Goodwill and intangible assets
In
REVENUE, OPERATING MARGIN(1) AND PLANT OUTPUT
---------------------------------------------------------
Three months ended September 30
-------------------------------------------------------------------------
(millions of 2009 2008
dollars except ---------------------------------------------------------
GWh) Operating Operating
(unaudited) GWh Revenue Margin(1) GWh Revenue Margin(1)
---------------------------------------------------------
Ontario plants 294 $ 29.0 $ 7.2 266 $ 37.7 $ 17.5
Williams Lake 47 10.8 8.4 132 10.7 7.7
Mamquam and Queen
Charlotte 43 2.9 1.6 68 4.1 3.1
Northwest US
plants 360 15.6 9.0 305 16.1 4.8
California plants 248 29.4 15.8 205 45.6 16.5
Curtis Palmer 59 6.9 5.4 50 5.6 4.6
Northeast US
natural gas
plants(2) 171 21.0 6.3 45 6.6 0.4
North Carolina
plants 6 6.2 (0.9) 176 20.8 1.5
PERC management
fees 1.0 0.6 0.9 0.6
---------------------------------------------------------
1,228 122.8 53.4 1,247 148.1 56.7
Fair value
changes
Foreign
exchange
contracts 32.7 32.7 (14.6) (14.6)
Natural gas
supply
contracts - (20.2) - (160.5)
---------------------------------------------------------
1,228 $ 155.5 $ 65.9 1,247 $ 133.5 $ (118.4)
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Nine months ended September 30
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(millions of 2009 2008
dollars except ---------------------------------------------------------
GWh) Operating Operating
(unaudited) GWh Revenue Margin(1) GWh Revenue Margin(1)
---------------------------------------------------------
Ontario plants 979 $ 105.2 $ 36.7 888 $ 119.6 $ 51.2
Williams Lake 216 31.9 21.0 355 28.8 18.8
Mamquam and Queen
Charlotte 162 10.9 7.5 182 12.2 8.8
Northwest US
plants 697 47.7 27.3 611 45.1 21.9
California plants 697 75.9 26.9 674 116.7 29.2
Curtis Palmer 248 30.1 25.7 242 24.7 21.2
Northeast US
natural gas
plants(2) 499 69.8 14.6 128 21.0 2.1
North Carolina
plants 62 23.4 (6.3) 492 48.7 2.6
PERC management
fees 2.9 1.9 2.6 1.8
---------------------------------------------------------
3,560 397.8 155.3 3,572 419.4 157.6
Fair value
changes
Foreign
exchange
contracts 50.5 50.5 (23.9) (23.9)
Natural gas
supply
contracts (53.0) 9.8
---------------------------------------------------------
3,560 $448.3 $152.8 3,572 $395.5 $143.5
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(1) Operating margin is not a defined financial measure according to
Canadian GAAP, and does not have a standardized meaning prescribed by
GAAP. See "Non-GAAP Measures".
(2) Includes the results of Morris from the date of acquisition of
October 31, 2008. Restated to reflect the operations of Castleton as
discontinued operations.
Weighted average plant Three months ended Nine months ended
availability(1) September 30 September 30
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2009 2008 2009 2008
------------------------------------------
Ontario plants 84% 97% 92% 96%
Williams Lake 100% 98% 97% 87%
Mamquam and Queen Charlotte 77% 85% 85% 84%
Northwest US plants 100% 99% 97% 93%
California plants 94% 94% 91% 92%
Curtis Palmer 92% 57% 90% 85%
Northeast US natural gas
plants(2) 100% 98% 99% 96%
North Carolina plants 77% 100% 73% 98%
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Weighted average total 93% 95% 92% 93%
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(1) Plant availability represents the percentage of time in the period
that the plant is available to generate power, whether actually
running or not, and is reduced by planned and unplanned outages.
(2) Includes the results of Morris from the date of acquisition of
October 31, 2008. Restated to reflect the operations of Castleton as
discontinued operations.
Operating margin excluding fair value changes in foreign exchange and natural gas supply contracts for the three and nine months ended
Revenue excluding fair value changes in foreign exchange contracts for the three and nine months ended
Unrealized fair value changes in derivative instruments recorded for accounting purposes are not representative of their economic value when considering them in conjunction with the economically hedged item such as future natural gas purchases, future power sales or future US dollar cash flows.
Ontario Plants
The Ontario plants reported operating margin of
Revenue from Ontario plants Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
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Power 27.3 26.2 99.0 92.4
Enhancements 0.7 7.0 1.3 17.6
Gas diversions 1.0 4.5 4.9 9.6
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29.0 37.7 105.2 119.6
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Revenues from the Ontario plants were lower for the three and nine months ended
Operating margin from
Generation during the three and nine months ended
Mamquam and Queen Charlotte
Operating margin at Mamquam and
Northwest US Plants
Operating margin from Frederickson was
Operating margin from Manchief was
Operating margin from Greeley was
California Plants
Operating margin from the Naval facilities was
Operating margin from Oxnard was
Operating margin from
Northeast US Natural Gas Plants
Operating margin from Morris, which was acquired on
Operating margin from Kenilworth was
North
The North Carolina plants reported operating margin losses of
The decrease in operating margin was also the result of higher maintenance costs for planned repairs as well as for a generator failure at Roxboro. The Roxboro unit returned to service in
Fair value changes
Unrealized gains on foreign exchange contracts were
The Partnership recorded fair value losses on natural gas supply contracts of
COST OF FUEL
Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
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Ontario plants
Natural gas 16.9 14.6 51.6 48.7
Waste heat 0.5 1.3 3.0 6.3
Wood waste 0.1 0.6 2.0 2.1
------- ------- ------- -------
17.5 16.5 56.6 57.1
Williams Lake - wood waste 0.5 0.8 3.8 2.0
Northwest US plants - natural
gas 2.9 2.8 8.9 8.8
California plants - natural gas 9.5 23.6 33.8 70.7
Northeast US natural gas
plants(1) 12.2 5.4 46.6 16.8
North Carolina plants - coal,
tire-derived fuel & wood waste 2.7 15.3 12.8 34.4
------- ------- ------- -------
45.3 64.4 162.5 189.8
Fair value changes on natural
gas contracts 20.2 160.5 53.0 (9.8)
------- ------- ------- -------
65.5 224.9 215.5 180.0
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(1) Includes the results of Morris from the date of acquisition of
October 31, 2008. Restated to reflect the operations of Castleton as
discontinued operations.
Fuel costs, which are the Partnership's most significant cost of operations, include commodity costs, transportation costs and fair value changes on natural gas supply contracts.
For the three and nine months ended
Fuel costs at the Ontario plants for the three months ended
The Northwest US plants incurred fuel costs of
Fuel costs at the California facilities were
The Northeast US natural gas plants incurred fuel costs of
The North Carolina plants incurred fuel costs of
The
OPERATING AND MAINTENANCE EXPENSE
Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
Ontario plants 4.3 3.7 11.9 11.3
Williams Lake 1.9 2.2 7.1 8.0
Mamquam and Queen Charlotte 1.3 1.0 3.4 3.4
Northwest US plants 3.7 8.5 11.5 14.4
California plants 4.1 5.5 15.2 16.8
Curtis Palmer 1.5 1.0 4.4 3.5
Northeast US natural gas
plants(1) 2.5 0.8 8.6 2.1
North Carolina plants 4.4 4.0 16.9 11.7
PERC management expenses 0.4 0.3 1.0 0.8
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24.1 27.0 80.0 72.0
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(1) Includes the results of Morris from the date of acquisition of
October 31, 2008. Restated to reflect the operations of Castleton as
discontinued operations.
Operating and maintenance expenses include payments to the Manager and third parties for the operation and routine maintenance of the plants. Fees paid to the Manager are based on fixed charges adjusted annually for inflation for the Canadian plants,
DEPRECIATION AND AMORTIZATION
Depreciation and amortization expense for the three and nine months ended
MANAGEMENT AND ADMINISTRATION
Management and administration costs, which include fees payable to CPC (and prior to
FOREIGN EXCHANGE LOSSES
The Partnership reported net foreign exchange losses of
EQUITY LOSSES IN PERH
Equity losses in Primary Energy Recycling Holdings LLC (PERH) were from the Partnership's common ownership interest in PERH, which was accounted for on the equity basis up to
For the three and nine months ended
Concurrently with the PERH recapitalization, certain changes were made to the long-term management agreement pursuant to which a wholly-owned subsidiary of the Partnership provides management and administrative services to PERH, certain subsidiaries of PERH and to PERC. The changes include: (i) PERH has assumed responsibility for certain management functions, (ii) the parties agreed that PERH can terminate the management agreement for a specified price, declining over time, if the Partnership agrees to sell its interest in PERH, and (iii) the allocation agreement among the Partnership, PERC and certain other parties, together with the rights of first offer in respect of certain projects of the Partnership granted to PERC and to PERH under the management agreement and the allocation agreement, has been terminated. PERC has announced that the US$131 million term loan facility in a PERH subsidiary has been amended to extend the maturity date of the loan from
PERC has filed a prospectus qualifying the issuance of rights to acquire subscription receipts which will be converted into common shares of PERC upon PERC obtaining sufficient funds to refinance the credit facility. PERC has advised that upon such occurrence, PERC immediately intends to use the net proceeds of the rights offering to subscribe for new common membership interests in PERH. The Partnership has a pre-emptive right to maintain its current pro-rata interest (14.3%) in PERH. The Partnership has determined that it will exercise it pre-emptive right, subject to changes in circumstances prior to the close of the rights offering that may cause the Partnership to reconsider this decision. If the Partnership exercises its pre-emptive right, the Partnership will be required to subscribe for new common membership interests at an aggregate subscription price of US$8.3 million concurrently with PERC's subscription. The Partnership will finance the subscription with cash on hand or by drawing on its revolving credit facilities.
FINANCIAL CHARGES AND OTHER, NET
Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
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Interest on long-term debt 10.4 9.8 32.1 28.5
Interest on short-term debt - 0.2 0.6 0.5
Capitalized interest (0.2) - (0.2) -
Dividend income from Class B
preferred share interests in
PERH (0.4) (0.5) (1.1) (1.4)
Other 0.4 (0.3) 0.2 (0.2)
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10.2 9.2 31.6 27.4
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Financial charges and other expenses were
INCOME TAX RECOVERY
Income tax recoveries were
During the quarter ended
The remaining changes were mainly due to future income taxes on changes in temporary differences primarily related to changes in the fair value of natural gas supply and foreign exchange contracts which are expected to reverse after 2010. Currently, the taxable income of the Partnership is expected to be taxed in the hands of unitholders. After 2010, the Partnership expects taxes will be applied at the Partnership level as changes to Canadian tax legislation become effective.
Withholding taxes on payments between US and Canadian subsidiaries, excluding dividends, are expected to be eliminated by 2010 from the current 4% rate on payments made in 2009.
PREFERRED SHARE DIVIDENDS OF A SUBSIDIARY COMPANY
A subsidiary of the Partnership issued Series 1 preferred shares, which pay dividends at a rate of 4.85% per annum. For the three and nine months ended
LIQUIDITY AND CAPITAL RESOURCES
Cash distributions
In the second quarter of 2009, the Partnership reduced its distribution from
When cash provided by operating activities exceeds cash distributions and maintenance capital expenditures, the Partnership utilizes the difference to stabilize future quarterly cash distributions, to finance growth capital expenditures and to make debt repayments. When cash provided by operating activities is less than cash distributions and maintenance capital expenditures, the Partnership utilizes available cash balances and short-term financing to cover the shortfall. The ability of the Partnership to sustain current cash flow is subject to the Partnership finding cash accretive investments to replace expected future declines in cash flow as contracts expire.
Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
Cash distributions 23.7 34.0 81.4 101.9
Cash provided by operating
activities of continuing
operations 33.8 20.0 100.6 101.0
Net income (loss) from
continuing operations 30.7 (152.2) 40.2 6.2
Payout ratio(1) 71% 89% 89% 107%
Dividends from PERH - 0.8 1.3 2.4
Additions to property, plant
and equipment 33.0 5.1 75.9 18.5
Excess (shortfall) of cash
provided by operating activities
of continuing operations over
cash distributions 10.1 (14.0) 19.2 (0.9)
Excess (shortfall) of net income
(loss) from continuing operations
over cash distributions 7.0 (186.2) (41.2) (95.7)
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(1) Payout ratio is cash distributions divided by cash provided by
operating activities of continuing operations excluding changes in
working capital less maintenance capital expenditures.
Cash provided by operating activities of continuing operations exceeded cash distributions by
Net income is not necessarily comparable to cash distributions as net income includes items such as changes in the fair value of derivative instruments. Aside from these items, management expects that distributions will exceed net income. Accordingly, a portion of the distributions represent a return of capital. To date, and subject to ensuring adequate liquidity, the Partnership has chosen to make distributions that include a return of capital.
To the extent there is a shortfall between the Partnership's cash provided by operating activities and cash distributions and capital expenditures, the Partnership has available to it two revolving credit facilities, each of
The third quarter 2009 cash distribution of
Capital expenditures
Capital expenditures for the three and nine months ended
Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
Maintenance capital expenditures 3.9 3.2 16.0 14.9
North Carolina enhancement
project 23.7 1.9 41.6 3.6
North Island turbine replacement
project 1.1 - 14.0 -
Oxnard turbine replacement project 4.3 - 4.3 -
-------------------------------------------------------------------------
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33.0 5.1 75.9 18.5
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The North Carolina enhancement project is nearing completion of the installation phase and the project in service date remains
During the second quarter of 2009 the Partnership completed the repowering of the natural gas turbine at North Island to improve plant efficiency and financial performance. Project costs incurred to date were
The Partnership has initiated a similar repowering project at Oxnard to be completed in 2010. Total cost of the project is expected to be approximately
In
Financing
The following table summarizes the long-term debt of the Partnership.
September 30 December 31
(millions of dollars)(unaudited) 2009 2008
-------------------------------------------------------------------------
Senior unsecured notes, due 2036 210.0 210.0
Senior unsecured notes (US$415.0) due 2014 to 2019 444.4 505.5
Secured term loan, due 2010 1.4 2.6
Revolving credit facilities 141.6 86.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
797.4 804.8
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The Partnership's debt to total capitalization ratio as at
Debt (short-term debt + long-term debt)
Debt to total capitalization
ratio = ------------------------------------------
Debt + preferred shares + partners' equity
Under the terms of its debt agreements, the Partnership must maintain a debt to capitalization ratio of not more than 65% at the end of each fiscal quarter. During the nine months ended
In the second quarter of 2009, DBRS lowered its outlook for the Partnership from stable trend to negative trend and reduced its stability rating from STA-2(high) to STA-2(low) as a result of increasing debt levels. At the same time, DBRS confirmed its BBB(high) with a negative trend credit rating. In
The BBB+ debt rating by S&P is the fourth highest rating out of 10 rating categories. The plus sign shows the relative standing within the major rating categories. DBRS' BBB(high) rating designates the Partnership's debt as being of satisfactory credit quality with the protection of interest and principal still substantial. The "BBB" rating is DBRS' fourth highest of 10 categories. The high classification shows the relative standing within the major rating categories.
Having an investment grade credit rating improves the Partnership's ability to re-finance existing debt as it matures and to access cost competitive capital for future growth.
The stability ratings of SR-2 by S&P is the second highest rating of seven categories and indicates that the Partnership has a high level of distributable cash generation stability relative to other rated Canadian income funds. The STA-2 (low) stability rating by DBRS is the second highest of seven categories in their rating system for income fund stability. DBRS further subcategorizes each rating by the designation of "high", "middle" and "low" to indicate where an entity falls within the rating category.
Financial market liquidity
The exposure of the Partnership to the ongoing volatility in the Canadian and US financial markets is substantially unchanged from
Long-term debt principal repayment
(unaudited) (millions of dollars)
-------------------------------------------------------------------------
2010 1.4
2011 141.6
2014 203.5
2017 160.6
2019 80.3
2036 210.0
-------------------------------------------------------------------------
The Partnership expects to borrow an additional US$30 million to US$35 million on its credit facilities to fund the completion of the North Carolina capital project in 2009 and expects to repay a portion of the revolving credit facilities that mature in 2011 with the proceeds of the
Further, the Partnership has established a Premium Distribution Reinvestment Program to foster its capacity for growth (see Significant Events - Launch of Distribution Reinvestment Plan).
Uncertainty in global financial markets and, in particular, the Canadian and US financial markets may adversely affect the Partnership's ability to arrange permanent long-term financing for large acquisitions or development opportunities.
FOREIGN EXCHANGE RISK MANAGEMENT
The Partnership manages the foreign exchange risk of its anticipated US dollar-denominated cash flows from its US plants through the use of forward foreign exchange contracts for periods up to seven years. As at
TRANSACTIONS WITH RELATED PARTIES
Three months ended Nine months ended
(millions of dollars) September 30 September 30
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
Transactions with CPC(1)
------------------------
Revenue - Frederickson duct
firing capacity fees - - 0.1 -
Cost of fuel - Greeley natural
gas contract 0.7 - 2.2 -
Operating and maintenance expense 11.9 10.7 38.4 32.6
Management and administration
Base fee 0.2 0.3 0.8 1.0
Incentive fee - 0.5 - 1.7
Enhancement fee 0.1 0.9 0.2 2.3
General and administrative costs 2.1 1.4 5.9 4.2
-------------------------------------------------------------------------
2.4 3.1 6.9 9.2
-------------------------------------------------------------------------
Transactions of discontinued
operations
Cost of fuel - Castleton natural
gas demand charge 0.1 0.6 1.1 1.6
Operating and maintenance
expense - Castleton - 0.7 1.4 2.1
-------------------------------------------------------------------------
0.1 1.3 2.5 3.7
-------------------------------------------------------------------------
Acquisition and divestiture fees - - 0.2 -
Transactions with PERH
----------------------
Revenue
Base management fees 0.6 0.9 2.5 2.6
-------------------------------------------------------------------------
(1) Prior to June 30, 2009, EPCOR.
In operating the Partnership's 20 power plants, the Partnership and CPC (and prior to
During the nine months ended
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES
The Partnership has committed up to US$20 million for the replacement of the turbine at Oxnard, to be spent over 2009 and 2010. There were no other material changes to the Partnership's purchase obligations, commitments or contingencies during the third quarter, including payments for the next five years and thereafter. For further information on these obligations, refer to the Partnership's
CRITICAL ACCOUNTING ESTIMATES
Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Partnership's consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. The Partnership's critical accounting estimates include tax provision calculations as a result of the Partnership becoming taxable in 2011, depreciation and amortization expense, asset retirement obligations and fair value estimates. For further information on the Partnership's critical accounting estimates, refer to the Partnership's
INTERNAL CONTROL OVER FINANCIAL REPORTING
During the period, the ownership and legal names of the Manager changed however there were no significant changes to the staff provided to the Partnership. Accordingly, there were no changes made to the Partnership's internal controls over financial reporting during the interim period ended
BUSINESS RISKS
The Partnership's business and operational risks remain substantially unchanged since
Proposed emissions regulation
On
On
The proposed Canadian federal regulatory framework known as "Turning the Corner", to reduce GHG emissions and air pollution, recommended an 18% reduction in GHG emissions intensity starting in 2010 and increasing by 2% per year thereafter resulting in a 20% absolute reduction in GHG emissions from 2006 levels by 2020, and a 50% reduction in air pollution by 2015. Subsequently released government information indicates that some or all of these proposed compliance dates will be extended, starting in 2012 as opposed to 2010.
The Partnership is assessing the potential impact of these initiatives, but at this time there is insufficient information to assess the full financial and operational implications on the Partnership's facilities. To the extent that additional regulation is passed, the Partnership could incur increased costs.
FUTURE ACCOUNTING STANDARDS
International financial reporting standards
In
The Partnership's plan for conversion to and implementation of these international standards has not changed substantially since
Fair value measurement disclosure
In
Consolidated financial statements and non-controlling interests
In
Sections 1601 and 1602 will apply to the Partnership's interim and annual consolidated financial statements relating to periods commencing on or after
Business combinations
In
OUTLOOK
In a news release dated
The revised expectations primarily reflect lower expected operating margins at the North Carolina generation facilities (Southport and Roxboro). As disclosed in the Partnership's second quarter MD&A in
The current PPAs for the North Carolina facilities expire on
The Partnership noted that in
In its new build application, Progress indicated that its full cost of generation from this repowered facility would approximate
The Partnership had finalized a petition for arbitration when the NCUC issued its Order. Following the NCUC's issuance of the Order, the Partnership has sent Progress a proposal setting forth an accelerated timeframe for restarting and finalizing negotiations. If negotiations are unsuccessful, the Partnership will file for arbitration. The Partnership remains optimistic that either a NCUC arbitration ruling or further negotiations with Progress will result in new PPAs for the Roxboro and Southport facilities. It is not certain at this time whether the final contract terms will immediately result in positive cash provided by operating activities for the facilities or achieve previous expectations of accretion from the North Carolina enhancement project. The Partnership's long-term outlook for the North Carolina plants remains positive as current modifications to the facilities are nearing completion that will significantly reduce coal use and replace it with more wood waste that will substantially reduce greenhouse gas emissions and increase the production of renewable energy to meet North Carolina's renewable energy requirements.
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
(unaudited)
(millions of dollars 2009 2008
except per unit amounts) Third Second First Fourth
-------------------------------------------------------------------------
Revenues 155.5 165.2 127.6 103.8
Operating margin(1) 65.9 87.7 (0.8) (32.1)
Net income (loss) from
continuing operations 30.7 42.3 (32.6) (73.3)
Net income (loss) 30.7 42.8 (33.3) (73.1)
Cash provided by operating
activities of continuing
operations 33.8 33.1 33.7 56.5
Capital expenditures 33.0 25.9 17.0 21.5
Cash distributions 23.7 23.7 34.0 33.9
Per unit statistics
Net income (loss) from
continuing operations $ 0.57 $ 0.78 $ (0.60) $ (1.36)
Cash provided by operating
activities of continuing
operations(1) $ 0.63 $ 0.61 $ 0.63 $ 1.05
Cash distributions $ 0.44 $ 0.44 $ 0.63 $ 0.63
-------------------------------------------------------------------------
(unaudited)
(millions of dollars 2008 2007
except per unit amounts) Third Second First Fourth
-------------------------------------------------------------------------
Revenues 133.5 143.9 118.1 114.1
Operating margin(1) (118.4) 155.1 106.8 81.5
Net income (loss) from
continuing operations (152.2) 105.1 53.3 45.3
Net income (loss) (153.0) 104.9 53.4 45.3
Cash provided by operating
activities of continuing
operations 20.0 39.4 41.6 35.7
Capital expenditures 5.1 10.0 3.4 4.1
Cash distributions 34.0 33.9 34.0 34.0
Per unit statistics
Net income (loss) from
continuing operations $ (2.82) $ 1.95 $ 0.99 $ 0.84
Cash provided by operating
activities of continuing
operations(1) $ 0.37 $ 0.73 $ 0.77 $ 0.66
Cash distributions $ 0.63 $ 0.63 $ 0.63 $ 0.63
-------------------------------------------------------------------------
(1) The selected quarterly consolidated financial data has been prepared
in accordance with GAAP except for operating margin and cash provided
by operating activities of continuing operations per unit.
See Non-GAAP Measures.
Factors impacting quarterly financial results
The Partnership's Selected Quarterly Financial Data, which has been prepared in accordance with GAAP, except as noted, is set out above. Quarterly revenues, net income and cash provided by operating activities are affected by seasonal contract pricing, seasonal weather conditions, fluctuations in US dollar exchange rates relative to the Canadian dollar, attainment of firm energy requirements, natural gas prices, waste heat availability and planned and unplanned plant outages, as well as items outside of the normal course of operations. Quarterly net income is also affected by unrealized foreign exchange gains and losses primarily on the Partnership's US dollar-denominated long-term debt prior to the fourth quarter of 2008 and fair value changes in foreign exchange contracts and natural gas supply contracts.
The Partnership's cash flow tends to be relatively stable over the year with seasonal fluctuations at the individual facilities. The Naval facilities earn approximately 75% of their capacity revenue during the summer peak demand months and all the California plants can earn performance bonuses during these months. Under the power sales contracts for the Ontario plants, the Partnership receives higher per megawatt hour prices in the winter months (October to March) and lower prices in the summer months (April to September). The lower summer prices reduce the threshold for economic curtailments thereby increasing the profitability of enhancements, natural gas prices being equal. Contributions from
Significant items which impacted the last eight quarters' net income were as follows:
In the fourth quarter of 2008, the Partnership acquired Morris.
In the fourth quarter of 2008, the Partnership recorded a
In the third quarter of 2008 the Partnership recorded a
Unrealized foreign exchange gains on US dollar-denominated debt were recorded in the fourth quarter of 2007 and the second quarter of 2008. Losses were recorded in the first and third quarters of 2008. The gains and losses are due to fluctuations in the US dollar relative to the Canadian dollar.
The Partnership recorded gains on the change in the fair value of the natural gas supply contracts in the fourth quarter of 2007 and the first and second quarters of 2008 and the second quarter of 2009 and losses in the third and fourth quarters of 2008 and the first and third quarters of 2009.
Unrealized fair value changes on foreign exchange contracts resulted in gains in the second quarter of 2008 and the second and third quarters of 2009. Losses were recorded in the fourth quarter of 2007, in the first, third and fourth quarters of 2008 and in the first quarter of 2009.
The first quarter of 2008 had unseasonably high water flows at
FORWARD-LOOKING INFORMATION
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 the Partnership's actual results and experience to be materially different than the anticipated results. In particular, forward-looking information and statements include (i) the sustainability of distributions, including relative to a long-term payout ratio target of 75% of cash provided by operating activities less maintenance capital; (ii) planned capital upgrades at Southport and Roxboro of US$80 million, (iii) planned capital upgrades at Oxnard of US$20 million, (iv) expectations regarding the in service timeline for additional facilities at Manchief, (v) expectations regarding the Partnership's cash provided by operating activities, dividends received from PERH, capital expenditures generally and working capital in 2009, (vi) expectations regarding the cash to be retained by the Partnership as a result of the distribution reduction and the expected uses of that cash, (vii) anticipated closed date of the preferred share offering, (viii) expectations regarding the financing of the Partnership's capital expenditures (ix) expectations with regard to the operating margin and dispatch levels for the North Carolina facilities, * managements expectations in respect of new PPA's for the Southport and Roxboro facilities, (xi) with respect to the Partnership's long-term outlook for the North Carolina plants, (xii) anticipated completion of the Roxboro and Southport facility modifications and the impact thereof on the operation of the facilities, (xiii) the expectation that the Roxboro facility will be re-certified as a QF by the end of 2009, and (xiv) that the Partnership will apply to the NCUC to arbitrate if an agreement for a new PPA with Progress is not reached.
These statements are based on certain assumptions and analyses made by the Partnership 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 used to develop these forward-looking statements include: (i) the Partnership's operations, financial position and available credit facilities, (ii) the Partnership's assessment of commodity, currency and power markets, (iii) the markets and regulatory environment in which the Partnership's facilities operate, (iv) the state of capital markets, (v) management's analysis of applicable tax legislation, (vi) the assumption that the currently applicable and proposed tax laws will not change and will be implemented, (vii) the assumption that counterparties to fuel supply and power purchase agreements will continue to perform their obligations under the agreements taking account of the matters described herein, (viii) the level of plant availability and dispatch, (ix) the performance of contractors and suppliers, * the renewal or replacement of PPAs and terms of PPAs (xi) the ability of the Partnership to successfully integrate and realize the benefits of its acquisitions, (xii) the ability of the Partnership to implement its strategic initiatives and whether such initiatives will yield the expected benefits, (xiii) expected water flows, and (xiv) the ability of the Partnership to adequately source alternative sources of supply of wood waste.
Whether actual results, performance or achievements will conform to the Partnership's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from the Partnership's expectations. Such risks and uncertainties include, but are not limited to risks relating to (i) the operation of the Partnership's facilities, (ii) plant availability and performance, (iii) the availability and price of energy commodities including natural gas and wood waste, (iv) the performance of counterparties in meeting their obligations under PPAs, (v) competitive factors in the power industry, (vi) economic conditions, including in the markets served by the Partnership's facilities, (vii) ongoing compliance by the Partnership with its current debt covenants, (viii) developments within the North American capital markets, (ix) the availability and cost of permanent long-term financing in respect of acquisitions and investments, * unanticipated maintenance and other expenditures, (xi) the Partnership's ability to successfully realize the benefits of acquisitions and investments, (xii) changes in regulatory and government decisions including changes to emission regulations, (xiii) waste heat availability and water flows, (xiv) changes in existing and proposed tax and other legislation in
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. Forward-looking statements are provided for the purpose of presenting information about management's current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. Except as required by law, the Partnership disclaims any intention and assumes no obligation to update any forward-looking statement.
QUARTERLY UNIT TRADING INFORMATION
The Partnership units trade on the
For the three months Sep. 30 Jun. 30 Mar. 31 Dec. 31 Sep. 30
ended (unaudited) 2009 2009 2008 2008 2008
-------------------------------------------------------------------------
Unit price
High $16.30 $16.21 $18.98 $20.65 $23.50
Low $13.62 $11.65 $12.90 $15.50 $19.83
Close $15.26 $15.25 $13.80 $17.72 $20.32
Volume traded (millions) 4.3 9.2 3.3 5.1 3.6
-------------------------------------------------------------------------
As at
ADDITIONAL INFORMATION
Additional information relating to EPCOR Power L.P. including the Partnership's Annual Information Form and continuous disclosure documents are available on SEDAR at www.sedar.com.
EPCOR Power L.P.
CONSOLIDATED STATEMENTS OF INCOME AND LOSS
Three months ended Nine months ended
September 30 September 30
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
(In millions of dollars except
units and per unit amounts)
Revenues $ 155.5 $ 133.5 $ 448.3 $ 395.5
Cost of fuel 65.5 224.9 215.5 180.0
Operating and maintenance
expense 24.1 27.0 80.0 72.0
---------- ---------- ---------- ----------
65.9 (118.4) 152.8 143.5
Other costs
Depreciation and amortization 22.9 22.8 70.0 66.6
Management and administration 3.7 4.7 10.9 13.2
Foreign exchange losses 0.1 15.9 0.7 26.4
Equity losses in PERH 0.8 1.7 3.1 3.8
Financial charges and other,
net (Note 4) 10.2 9.2 31.6 27.4
---------- ---------- ---------- ----------
37.7 54.3 116.3 137.4
---------- ---------- ---------- ----------
Net income (loss) from
continuing operations
before income tax and
preferred share dividends 28.2 (172.7) 36.5 6.1
Income tax recovery (Note 5) (4.2) (22.1) (8.9) (5.0)
---------- ---------- ---------- ----------
Net income (loss) from
continuing operations
before preferred share
dividends 32.4 (150.6) 45.4 11.1
Preferred share dividends
of a subsidiary company 1.7 1.6 5.0 4.9
---------- ---------- ---------- ----------
Net income (loss) from
continuing operations 30.7 (152.2) 40.4 6.2
Loss from discontinued
operations, net of
income tax (Note 3) - (0.8) (0.2) (0.9)
---------- ---------- ---------- ----------
Net income (loss) $ 30.7 $ (153.0) $ 40.2 $ 5.3
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Net income (loss) per unit
from continuing operations $ 0.57 $ (2.82) $ 0.75 $ 0.12
Net loss per unit from dis-
continued operations $ - $ (0.01) $ 0.00 $ (0.02)
Net income (loss) per unit $ 0.57 $ (2.84) $ 0.75 $ 0.10
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Weighted average units
outstanding (millions) 53.9 53.9 53.9 53.9
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
See accompanying notes to the consolidated financial statements.
EPCOR Power L.P.
CONSOLIDATED STATEMENTS OF CASH FLOW
Three months ended Nine months ended
September 30 September 30
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
(In millions of dollars)
Operating activities
Net income (loss) from
continuing operations $ 30.7 $ (152.2) $ 40.4 $ 6.2
Items not affecting cash:
Depreciation and
amortization 22.9 22.8 70.0 66.6
Future income tax recovery (6.1) (23.1) (11.4) (8.6)
Fair value changes on
derivative instruments (12.5) 175.1 2.6 14.1
Unrealized foreign exchange
losses 0.2 16.0 0.5 26.3
Other 2.1 2.8 5.4 5.1
---------- ---------- ---------- ----------
37.3 41.4 107.5 109.7
Change in non-cash operating
working capital (3.5) (21.4) (6.9) (8.7)
---------- ---------- ---------- ----------
Cash provided by operating
activities of continuing
operations 33.8 20.0 100.6 101.0
Cash provided by (used in)
operating activities of
discontinued operations - 1.5 (2.8) 3.8
---------- ---------- ---------- ----------
Cash provided by operating
activities 33.8 21.5 97.8 104.8
---------- ---------- ---------- ----------
Investing activities
Additions to property, plant
and equipment (33.0) (5.1) (75.9) (18.5)
Change in non-cash working
capital 0.3 (3.5) (1.9) 0.1
Dividends from PERH - 0.8 1.3 2.4
---------- ---------- ---------- ----------
Cash used in investing
activities of continuing
operations (32.7) (7.8) (76.5) (16.0)
Cash (used in) provided by
investing activities of
discontinued operations - (3.4) 11.6 (3.4)
---------- ---------- ---------- ----------
Cash used in investing
activities (32.7) (11.2) (64.9) (19.4)
---------- ---------- ---------- ----------
Financing activities
Distributions paid (23.7) (33.9) (91.6) (101.8)
Net borrowings under credit
facilities 26.3 17.0 63.9 17.0
Long-term debt repaid (0.7) (0.6) (1.3) (1.1)
---------- ---------- ---------- ----------
Cash provided by (used in)
financing activities 1.9 (17.5) (29.0) (85.9)
---------- ---------- ---------- ----------
Foreign exchange (losses)
gains on cash held in a
foreign currency (0.6) 0.1 (1.4) 0.8
Increase (decrease) in
cash and cash equivalents 2.4 (7.1) 2.5 0.3
Cash and cash equivalents,
beginning of period 3.1 27.5 3.0 20.1
---------- ---------- ---------- ----------
Cash and cash equivalents,
end of period $ 5.5 $ 20.4 $ 5.5 $ 20.4
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Supplementary cash flow
information
Net income taxes paid
(recovered) $ (1.0) $ 2.5 $ 0.4 $ 7.0
Interest paid net of
interest received $ 14.4 $ 12.6 $ 36.8 $ 31.2
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
See accompanying notes to the consolidated financial statements.
EPCOR Power L.P.
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
(unaudited) 2009 2008
--------------------------------------------- ------------- -------------
(In millions of dollars)
ASSETS
Current assets
Cash and cash equivalents $ 5.5 $ 3.0
Accounts receivable 46.1 60.6
Inventories 22.7 23.2
Prepaids and other 7.2 5.0
Derivative instruments assets (Note 6) 6.0 22.8
Future income taxes 2.3 2.3
Current assets of discontinued operations - 2.3
------------- -------------
89.8 119.2
Property, plant and equipment 1,065.6 1,106.0
Power purchase arrangements 342.5 408.6
Long-term investments 12.9 19.2
Goodwill 48.4 55.1
Derivative instruments assets (Note 6) 28.4 27.1
Future income taxes 27.0 16.8
Other assets 39.0 45.2
Long-term assets of discontinued operations - 12.0
------------- -------------
$ 1,653.6 $ 1,809.2
------------- -------------
------------- -------------
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable $ 49.8 $ 70.3
Distributions payable 23.7 33.9
Long-term debt due within one year 1.4 1.3
Derivative instruments liabilities (Note 6) 2.6 13.0
Current liabilities of discontinued operations - 1.2
------------- -------------
77.5 119.7
Asset retirement obligations 28.6 28.6
Long-term debt 791.1 798.5
Derivative instruments liabilities (Note 6) 26.9 38.5
Contract liabilities 2.3 4.7
Future income taxes 63.1 60.7
Long-term liabilities of discontinued operations - 4.2
Preferred shares issued by a subsidiary company 122.0 122.0
Partners' equity 542.1 632.3
Commitments (Note 8)
Subsequent events (Note 9)
------------- -------------
$ 1,653.6 $ 1,809.2
------------- -------------
------------- -------------
See accompanying notes to the consolidated financial statements.
EPCOR Power L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY
Nine months ended September 30
(unaudited) 2009 2008
--------------------------------------------- ------------- -------------
(In millions of dollars)
Partnership capital
Balance, beginning of period $ 1,197.1 $ 1,197.1
Issue of partnership units - -
------------- -------------
Balance, end of period $ 1,197.1 $ 1,197.1
------------- -------------
------------- -------------
Deficit
Balance, beginning of period:
As previously reported $ (500.1) $ (296.5)
Adjustment for changes in accounting
policies (Note 2) 3.9 -
------------- -------------
As restated (496.2) (296.5)
Net income 40.2 5.3
Cash distributions (81.4) (101.9)
------------- -------------
Balance, end of period $ (537.4) $ (393.1)
------------- -------------
Accumulated other comprehensive
(loss) income
Balance, beginning of period $ (64.7) $ 5.1
Other comprehensive loss (52.9) (2.9)
------------- -------------
Balance, end of period $ (117.6) $ 2.2
------------- -------------
Total of deficit and accumulated ------------- -------------
other comprehensive (loss) income $ (655.0) $ (390.9)
------------- -------------
------------- -------------
Partners' equity $ 542.1 $ 806.2
------------- -------------
------------- -------------
See accompanying notes to the consolidated financial statements.
EPCOR Power L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND LOSS
Three months ended Nine months ended
September 30 September 30
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
(In millions of dollars)
Net income (loss) $ 30.7 $ (153.0) $ 40.2 $ 5.3
Other comprehensive loss,
net of income tax
Losses on translating net
assets of self-sustaining
foreign operations(1) (32.8) - (56.7) -
Amortization of deferred
gains on derivatives
de-designated as cash flow
hedges to income(1) - (1.0) (0.4) (2.9)
Unrealized gains on derivative
instruments designated
as cash flow hedges(2) 4.2 - 4.2 -
---------- ---------- ---------- ----------
(28.6) (1.0) (52.9) (2.9)
Comprehensive income (loss) $ 2.1 $ (154.0) $ (12.7) $ 2.4
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
(1) Net of income tax of nil.
(2) Net of income tax of $0.1 for the three and nine months ended
September 30, 2009.
See accompanying notes to the consolidated financial statements.
EPCOR Power L.P.
Notes to the Interim Consolidated Financial Statements
September 30, 2009
(Unaudited)
Note 1. Significant accounting policies
The consolidated financial statements of EPCOR Power L.P. (the Partnership) have been prepared by the management of the General Partner in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in the Partnership's annual financial statements for the year ended
Quarterly revenues, net income and cash provided by operating activities are affected by seasonal contract pricing, seasonal weather conditions, fluctuations in
Since a determination of many assets, liabilities, revenues and expenses is dependent on future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions which have been made with careful judgment. In the opinion of management of the Partnership's General Partner, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Partnership's accounting policies.
Note 2. Changes in accounting policies
Credit risk and the fair value of financial assets and financial
liabilities
On
Balance sheet item Increase
(millions of dollars) (decrease) Explanation
----------------------------------------- ------------------------------
Derivative instruments assets (1.5) Impact to fair value of
Derivative instruments foreign exchange and
liabilities (6.3) natural gas contracts from
incorporating credit
risk of counterparties of the
Partnership.
Future income taxes Tax impact from adoption of
liabilities - non-current 0.9 new standard.
After tax impact to opening
deficit resulting from
Opening deficit (3.9) adoption of new standard.
----------- ------------------------------
Goodwill and intangible assets
In
Future accounting changes
International financial reporting standards
In 2005, the CICA announced plans to converge Canadian GAAP with IFRS over a transition period from 2006 to 2011. The CICA indicated that Canadian entities will be required to begin reporting under IFRS effective the first quarter of 2011 including comparative figures. A high level IFRS implementation plan has been developed and an assessment of the financial statement impact of the accounting standard differences is currently in progress. Based on the analysis to date, the most significant differences for the Partnership are anticipated to be related to property, plant and equipment, leases, joint arrangements, financial instruments and hedges, income taxes, impairments, business combinations, emission credits, asset retirement obligations and financial statement disclosure. The Partnership also expects to make changes to certain processes and systems before 2010, in time to ensure transactions are recorded in accordance with IFRS for comparative reporting purposes at the required implementation date.
Consolidated financial statements and non-controlling interests
In
Sections 1601 and 1602 will apply to the Partnership's interim and annual consolidated financial statements relating to periods commencing on or after
Business combinations
In
Fair value measurement disclosure
In
Derivative instruments and hedging activities
To reduce its exposure to movements in energy commodity prices, interest rate changes and foreign currency exchange rates, the Partnership uses various risk management techniques including the use of derivative instruments. Derivative instruments may include forward contracts, fixed-for-floating swaps, and option contracts. Such instruments may be used to establish a fixed price for an energy commodity, a cash flow denominated in a foreign currency or an interest-bearing obligation. All derivative instruments, including embedded derivatives, are recorded at fair value on the balance sheet as derivative instruments assets or derivative instruments liabilities except for embedded derivatives instruments that are clearly and closely linked to their host contract and the combined instrument is not measured at fair value. Any contract to buy or sell a non-financial item is not treated as a non-financial derivative if that contract was entered into and continues to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Partnership's expected purchase, sale or usage requirements. All changes in the fair value of derivatives are recorded in net income unless cash flow hedge accounting is used, in which case changes in fair value of the effective portion of the derivatives are recorded in other comprehensive income.
The Partnership uses non-financial forward delivery derivatives to manage the Partnership's exposure to fluctuations in natural gas prices related to obligations arising from its natural gas fired generation facilities. Under these instruments, the Partnership agrees to purchase natural gas at a fixed price for delivery of a pre-determined quantity under a specified timeframe.
Foreign exchange forward contracts are used by the Partnership to manage foreign exchange exposures, consisting mainly of US dollar exposures, resulting from anticipated transactions denominated in foreign currencies.
The Partnership may use forward interest rate or swap agreements and option agreements to manage the impact of fluctuating interest rates on existing debt.
The Partnership may use hedge accounting when there is a high degree of correlation between the risk in the item designated as being hedged (the hedged item) and the derivative instrument designated as a hedge (the hedging instrument). The Partnership documents all relationships between hedging instruments and hedged items at the hedge's inception, including its risk management objectives and its assessment of the effectiveness of the hedging relationship on a retrospective and prospective basis. The Partnership uses cash flow hedges for certain of its anticipated transactions to reduce exposure to fluctuations in changes in natural gas prices. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in other comprehensive income, while the ineffective portion is recognized in net income. The amounts recognized in accumulated other comprehensive income are reclassified into net income in the same period or periods in which the hedged item occurs and is recorded in net income or when the hedged item becomes probable of not occurring. The hedging relationship for the natural gas contracts was established after the inception of the contracts, which are derivative instruments. The fair value of these contracts at the date of hedge designation will be recognized in net income as the natural gas is delivered under the contracts based on the anticipated fair value of the deliveries at the inception of the hedging relationship.
The Partnership has not designated any fair value hedges at the balance sheet date.
A hedging relationship is discontinued if the hedge relationship ceases to be effective, if the hedged item is an anticipated transaction and it is probable that the transaction will not occur by the end of the originally specified time period, if the Partnership terminates its designation of the hedging relationship, or if either the hedged or hedging instrument ceases to exist as a result of its maturity, expiry, sale, termination or cancellation and is not replaced as part of the Partnership's hedging strategy.
If a cash flow hedging relationship is discontinued or ceases to be effective, any cumulative gains or losses arising prior to such time are deferred in accumulated other comprehensive income and recognized in net income in the same period as the hedged item, and subsequent changes in the fair value of the derivative instrument are reflected in net income. If the hedged or hedging item matures, expires, or is sold, extinguished or terminated and the hedging item is not replaced, any gains or losses associated with the hedging item that were previously recognized in other comprehensive income are recognized in net income in the same period as the corresponding gains or losses on the hedged item. When it is no longer probable that an anticipated transaction will occur within the originally determined period and the associated cash flow hedge has been discontinued, any gains or losses associated with the hedging item that were previously recognized in other comprehensive income are recognized in net income in the period.
When the conditions for hedge accounting cannot be applied, the changes in fair value of the derivative instruments are recognized as described above. The fair value of derivative financial instruments reflects changes in the commodity market prices and foreign exchange rates. Fair value is determined based on exchange or over-the-counter price quotations by reference to bid or asking price as appropriate, in active markets. In illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling techniques commonly used by market participants to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows. Fair value amounts reflect management's best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, discount rates for time value, and volatility where available. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.
Investment in PERH
The Partnership's common ownership interest in PERH was accounted for on the equity basis up to
Note 3. Discontinued operations
The Partnership completed the sale of its Castleton facility (Castleton) on
A summary of revenues and expenses of Castleton were as follows:
Three months ended Nine months ended
September 30 September 30
(millions of dollars) 2009 2008 2009 2008
-------------------------------------------------------------------------
Revenues $ - $ 4.4 $ 2.1 $ 11.2
Expenses
Cost of fuel - 3.9 2.1 5.0
Operating and maintenance
expense - 1.1 2.1 3.1
Depreciation and amortization - 0.3 - 3.4
Foreign exchange gains - (0.3) - (0.2)
--------- --------- --------- ---------
Loss from operations - (0.6) (2.1) (0.1)
Gain on sale of Castleton - - 2.4 -
--------- --------- --------- ---------
(Loss) income before income tax - (0.6) 0.3 (0.1)
Income tax expense - 0.2 0.5 0.8
--------- --------- --------- ---------
Loss from discontinued
operations $ - $ (0.8) $ (0.2) $ (0.9)
--------- --------- --------- ---------
--------- --------- --------- ---------
Note 4. Financial charges and other, net
Three months ended Nine months ended
September 30 September 30
(millions of dollars) 2009 2008 2009 2008
-------------------------------------------------------------------------
Interest on long-term debt $ 10.4 $ 9.8 $ 32.1 $ 28.5
Interest on short-term debt - 0.2 0.6 0.5
Capitalized interest (0.2) - (0.2) -
Dividend income from Class B
preferred share interests
in PERH (0.4) (0.5) (1.1) (1.4)
Other 0.4 (0.3) 0.2 (0.2)
--------- --------- --------- ---------
$ 10.2 $ 9.2 $ 31.6 $ 27.4
--------- --------- --------- ---------
--------- --------- --------- ---------
Note 5. Income taxes
During the quarter ended
Note 6. Financial instruments
Derivative instruments
Derivative instruments are held to manage financial risk related to energy procurement and treasury management. All derivative instruments, including embedded derivatives, are classified as held for trading and are recorded at fair value on the balance sheet as derivative instruments assets and derivative instruments liabilities unless exempted from derivative treatment as a normal purchase, sale or usage. All changes in their fair value are recorded in net income.
The derivative instruments assets and liabilities used for risk management purposes consist of the following:
(millions of dollars) September 30, 2009
-------------------------------------------------------------------------
Foreign
Natural gas exchange Total
--------------------- ------------
Hedges Non-hedges Non-hedges
-----------------------------------------------------
Derivative
instruments assets:
Current $ 0.8 $ 1.7 $ 3.5 $ 6.0
Non-current 0.4 7.8 20.2 28.4
Derivative
instruments
liabilities:
Current (1.6) (0.1) (0.9) (2.6)
Non-current (21.7) - (5.2) (26.9)
-----------------------------------------------------
$ (22.1) $ 9.4 $ 17.6 $ 4.9
-----------------------------------------------------
-----------------------------------------------------
Net notional
amounts:
Gigajoules (GJs)
(millions) 47 12
US foreign
exchange (US
dollars in
millions) 453.3
Contract terms
(years) 1.3 to 7.3 0.3 to 3.3 0.2 to 6.2
-----------------------------------------------------
(millions of dollars) December 31, 2008
-------------------------------------------------------------------------
Foreign
Natural gas exchange Total
--------------------- ------------
Hedges Non-hedges Non-hedges
-----------------------------------------------------
Derivative
instruments assets:
Current $ - $ 15.5 $ 7.3 $ 22.8
Non-current - 23.5 3.6 27.1
Derivative
instruments
liabilities:
Current - (1.5) (11.5) (13.0)
Non-current - (0.6) (37.9) (38.5)
-----------------------------------------------------
$ - $ 36.9 $ (38.5) $ (1.6)
-----------------------------------------------------
-----------------------------------------------------
Net notional
amounts:
Gigajoules (GJs)
(millions) - 69
US foreign
exchange (US
dollars in
millions) 456.9
Contract terms
(years) - 0.1 to 8.0 0.2 to 6.0
-----------------------------------------------------
The fair value of derivative instruments are determined, where possible, using exchange or over-the-counter price quotations by reference to quoted bid, ask, or closing market prices, as appropriate in active markets. Where there are limited observable prices due to illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling commonly used by market participants to estimate fair value. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. In general, fair value amounts reflect management's best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, discount rates for time value, and volatility for all of the Partnership's financial instruments. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material. With respect to natural gas the Partnership has determined the market is active to the end of the contract terms, a change from its previous assessment that the market was active within five years. In changing its assessment the Partnership considered market activity and the short period of time that the contracts extend beyond five years.
Unrealized and realized pre-tax gains and (losses) on derivative instruments recognized in net income and other comprehensive income were:
Income Three months ended Nine months ended
statement September 30 September 30
(millions of dollars) category 2009 2008 2009 2008
-------------------------------------------------------------------------
Foreign exchange
non-hedges Revenue $ 32.6 $ (11.1) $ 50.8 $ (13.3)
Natural gas Cost of
non-hedges fuel (20.2) (160.5) (53.0) 9.8
Foreign exchange Foreign
non-hedges exchange
losses
(gains) 0.1 0.1 (0.4) (0.1)
Natural gas Other
hedges compre-
hensive
income 4.3 - 4.3 -
--------- --------- --------- ---------
If hedge accounting requirements are not met, unrealized and realized gains and losses on natural gas derivatives are recorded in cost of fuel. If hedge accounting requirements are met, realized gains and losses on natural gas derivatives are recorded in cost of fuel while unrealized gains and losses are recorded in other comprehensive income.
The Partnership has elected to apply hedge accounting effective
Note 7. Segment disclosures
The Partnership operates in one reportable business segment involved in the operation of electrical generation plants within British Columbia, Ontario, and in the US in California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington.
Geographic information
Three months ended Three months ended
(millions of September 30 September 30
dollars) 2009 2008
------------------------------------------ ------------------------------
Canada US Total Canada US Total
------------------------------------------ ------------------------------
Revenue $ 75.2 $ 80.3 $ 155.5 $ 41.5 $ 92.0 $ 133.5
----------------------------- ------------------------------
----------------------------- ------------------------------
Nine months ended Nine months ended
(millions of September 30 September 30
dollars) 2009 2008
------------------------------------------ ------------------------------
Canada US Total Canada US Total
------------------------------------------ ------------------------------
Revenue $ 198.7 $ 249.6 $ 448.3 $ 147.3 $ 248.2 $ 395.5
----------------------------- ------------------------------
----------------------------- ------------------------------
(millions of
dollars) As at September 30, 2009 As at December 31, 2008
------------------------------------------ ------------------------------
Canada US Total Canada US Total
------------------------------------------ ------------------------------
Assets
PP&E $ 540.9 $ 524.7 $1,065.6 $ 559.3 $ 546.7 $1,106.0
PPAs 37.4 305.1 342.5 39.7 368.9 408.6
Other assets - 39.0 39.0 - 45.2 45.2
Goodwill - 48.4 48.4 - 55.1 55.1
----------------------------- ------------------------------
Total assets $ 578.3 $ 917.2 $1,495.5 $ 599.0 $1,015.9 $ 1,614.9
----------------------------- ------------------------------
----------------------------- ------------------------------
Note 8. Commitments
The Partnership has committed to spend an additional
The Partnership has committed up to
Note 9. Subsequent events
On
On
PERC has filed a prospectus qualifying the issuance of rights to acquire subscription receipts which will be converted into common shares of PERC upon PERC obtaining sufficient funds to refinance its credit facility. PERC has advised that upon such occurrence, PERC immediately intends to use the net proceeds of the rights offering to subscribe for new common membership interests in PERH. The Partnership has a pre-emptive right to maintain its current pro-rata interest (14.3%) in PERH. The Partnership has determined that it will exercise its pre-emptive right, subject to changes in circumstances prior to the close of the rights offering that may cause the Partnership to reconsider this decision. If the Partnership exercises its pre-emptive right, the Partnership will be required to subscribe for new common membership interests at an aggregate subscription price of US$8.3 million concurrently with PERC's subscription. The Partnership will finance the subscription with cash on hand or by drawing on its revolving credit facilities.
Note 10. Comparative figures
Certain comparative figures have been reclassified to conform to the current year's presentation.
--------------------------------
(TM) Denotes trademark of Canaccord Capital Corporation.
For further information: on the Partnership visit www.epcorpowerlp.ca or contact: Media Inquiries: Mike Long, (780) 392-5207; Unitholder & Analyst Inquiries: Randy Mah, (780) 392-5305, Toll Free (866) 896-4636
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