HALIFAX, Nov. 4 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net earnings
were $15.9 million in Q3, 2005, down from $22.1 million in Q3, 2004. The
earnings decrease reflects substantially lower earnings at Emera's largest
subsidiary, Nova Scotia Power Inc. (NSPI), which earned $2.7 million in the
quarter, compared to $18.5 million in Q3, 2004.
Emera's earnings per share were $0.14 in Q3, 2005, compared to $0.20 in
Q3, 2004.
"Nova Scotia Power continues to be affected by substantially higher fuel
costs that are not currently covered by rates," said Chris Huskilson,
President and Chief Executive Officer of Emera Inc. "Our 2006 rate
application, now before the Nova Scotia Utility and Review Board, addresses
this issue and we look forward to the hearings that begin November 14." NSPI's
fuel costs were $28.7 million, or 41% higher in Q3 2005 than for the same
period in 2004; and $78.2 million higher year to date, largely due to higher
coal and oil prices.
Emera's Other operations contributed $8.8 million to Q3, 2005
consolidated net earnings, compared to a loss of $1.2 million in Q3, 2004.
Foreign exchange gains and higher energy marketing margins were key drivers of
the higher earnings.
Bangor Hydro Electric (BHE), Emera's electricity transmission and
distribution utility in Maine, contributed $4.4 million to consolidated net
earnings in Q3, 2005, compared to $4.8 million in Q3, 2004, reflecting a
stronger Canadian dollar. BHE's U.S. dollar earnings were unchanged quarter
over quarter at $3.6 million.
Consolidated cash provided by operating activities was $116.7 million in
Q3, 2005, compared to $93.8 million in Q3, 2004.
About Emera Inc.
Emera Inc. (EMA-TSX) is an energy and services company with $4.0 billion
in assets. The core business of Emera is electricity and the company has two
wholly-owned regulated electric utility subsidiaries, Nova Scotia Power Inc.
and Bangor Hydro-Electric Company, which together serve 575,000 customers.
Nova Scotia Power supplies over 95% of the electric generation, transmission
and distribution in Nova Scotia. Nova Scotia Power's Point Tupper and Lingan
generating facilities have been ranked No. 1 and No. 2 in Canada in operating
performance by The Canadian Electricity Association. Bangor Hydro provides
electricity transmission and distribution service to 115,000 customers in
eastern Maine. It is a member of the New England Power Pool, and is
interconnected with the other New England utilities to the south and with New
Brunswick Power to the north. Emera also owns a 12.9% interest in the
Maritimes & Northeast Pipeline; and Emera Energy Services which manages energy
assets on behalf of third parties and provides related services. Visit Emera
on the web at www.emera.com.
Teleconference Call
Emera is holding a teleconference today at 3:00 pm Atlantic (2:00 pm
Toronto/Montreal/New York; 1:00 pm Winnipeg; 11:00 am Vancouver) to discuss
the Q3, 2005 financial results. Analysts and other interested parties wanting
to participate in the call should dial 1-866-898-9626 (in Toronto
416-340-2216) at least 10 minutes prior to the start of the call. No pass code
is required. The teleconference will be recorded. If you are unable to join
the teleconference live, you can dial for playback toll-free at 1-800-408-3053
(in Toronto 416-695-5800), access code 3165099 followed by the number sign
(available until midnight, Friday, November 11, 2005). The teleconference will
also be web cast live at www.emera.com and available for playback for one
year.
Forward Looking Information
This news release contains forward looking information. Actual future
results may differ materially. Additional financial and operational
information is filed electronically with various securities commissions in
Canada through the System for Electronic Document Analysis and Retrieval
(SEDAR).
Management's Discussion & Analysis
As at November 4, 2005
Management's Discussion and Analysis ("MD&A") provides a review of the
results of operations of Emera Inc. and its primary subsidiaries and
investments during the third quarter of 2005 relative to 2004, year to date
2005 relative to 2004, and its financial position at September 30, 2005
relative to December 31, 2004. Certain factors that may impact future
operations are also discussed. Such comments will be affected by, and may
involve, known and unknown risks and uncertainties that may cause the actual
results of the company to be materially different from those expressed or
implied. Those risks and uncertainties include, but are not limited to,
weather, commodity prices, interest rates, foreign exchange, regulatory
requirements and general economic conditions.
This discussion and analysis should be read in conjunction with the Emera
Inc. unaudited consolidated financial statements and supporting notes as at
and for the nine month period ended September 30, 2005, and the Emera Inc.
MD&A and annual audited consolidated financial statements and supporting notes
as at and for the year ended December 31, 2004. Emera follows Canadian
Generally Accepted Accounting Principles ("GAAP"). Emera's subsidiary, Nova
Scotia Power Inc.'s accounting policies are subject to examination and
approval by the Nova Scotia Utility and Review Board and are similar to those
being used by other companies in the electric utility industry in Canada.
Emera's subsidiary, Bangor Hydro-Electric Company's accounting policies are
subject to examination and approval by the Maine Public Utilities Commission
and the Federal Energy Regulatory Commission and are similar to those being
used by other companies in the electric utility industry in Maine. The
rate-regulated accounting policies of Nova Scotia Power and Bangor Hydro may
differ from GAAP for non rate-regulated companies.
Throughout this discussion, "Emera Inc." and "Emera" refer to Emera Inc.
and all of its consolidated subsidiaries and affiliates.
All amounts are in Canadian dollars ("CAD") except for the Bangor Hydro
section of the MD&A, which is reported in US dollars ("USD") unless otherwise
stated.
Additional information related to Emera, including the company's Annual
Information Form, can be found at SEDAR at www.sedar.com.
INTRODUCTION
The core business of Emera is electricity. The company operates two
regulated electric utilities in northeastern North America, which together
comprise approximately 90% of consolidated revenues:
- Nova Scotia Power Inc. ("NSPI") is a wholly-owned, fully integrated,
regulated electric utility, with $3.0 billion of assets, serving
460,000 customers. NSPI is the primary electricity supplier in Nova
Scotia, providing the vast majority of the generation, transmission
and distribution of electricity in the province. NSPI is regulated by
the Nova Scotia Utility and Review Board ("UARB").
- Bangor Hydro-Electric Company ("BHE") is a wholly-owned regulated
electricity transmission and distribution company with $600 million of
assets serving over 115,000 customers in eastern Maine. BHE's
transmission operations are regulated by the Federal Energy Regulatory
Commission ("FERC"), and its distribution operations are regulated by
the Maine Public Utilities Commission ("MPUC").
The success of Emera's electric utilities is integral to the creation of
shareholder value, providing substantial earnings and cash flow. Both
utilities are regulated monopolies, which can generally be expected to result
in relatively stable earnings streams, but limits upside earnings potential,
all other things being equal. Accordingly, Emera looks beyond its existing
regulated electricity business to supplement organic growth.
Emera's plan for growth seeks to add energy infrastructure assets to its
portfolio. The company is focused on building on its core electricity
business, specifically in regulated transmission and distribution operations,
and low risk generation facilities. Emera is concentrating its efforts in
northeastern North America, which is continuing to develop as an integrated
energy market. Most recently, in Q2, 2005 Emera, in a 50-50 joint venture with
Brascan Power, completed the acquisition of Bear Swamp, a 600 megawatt ("MW")
pumped storage hydro-electric facility in northern Massachusetts.
Structure of MD&A
This quarterly MD&A has been prepared in accordance with the Canadian
Securities Administrators National Instrument 51-102 Management's Discussion &
Analysis.
This Management's Discussion and Analysis begins with an overview of
quarterly consolidated results; then presents quarterly information on the
company's two primary subsidiaries, NSPI and BHE. All other operations,
including the Maritimes & Northeast Pipeline, Emera Energy Services, Emera
Fuels, Bear Swamp and corporate activities are grouped and discussed as
"Other". Significant changes in the consolidated balance sheets, outstanding
share data, liquidity and capital resources, financial and commodity
instruments, transactions with related parties, changes in accounting
policies, and selected quarterly trend information are presented on a
consolidated basis.
<<
EMERA CONSOLIDATED
Q3 Operating Unit Contributions
(millions of dollars, except Three months ended Nine months ended
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Nova Scotia Power $2.7 $18.5 $57.2 $82.3
Bangor Hydro-Electric 4.4 4.8 10.9 14.1
Other 8.8 (1.2) 15.4 2.0
-------------------------------------------------------------------------
Consolidated net earnings $15.9 $22.1 $83.5 $98.4
-------------------------------------------------------------------------
Earnings per common share - basic $0.14 $0.20 $0.76 $0.91
-------------------------------------------------------------------------
Earnings per common share - diluted $0.14 $0.20 $0.76 $0.88
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of Q3, 2005
Emera Inc.'s consolidated earnings decreased $6.2 million, to
$15.9 million in Q3, 2005 compared to $22.1 million for the same period in
2004. Year to date Emera's consolidated net earnings were $83.5 million in
2005 compared to $98.4 million in 2004. Highlights of the changes are
summarized in the following table:
Three months Nine months
ended ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
Consolidated net earnings - 2004 $22.1 $98.4
Increased electric revenue in NSPI due to the
5.3% rate increase effective April 1, 2005 10.4 23.0
Increased fuel expense in NSPI due to higher
commodity prices and year to date reduced
gas sales margin (28.7) (78.2)
Increased operating expenses in NSPI, reflecting
increased planned plant maintenance, storm
costs, and vegetation management costs (5.7) (9.1)
Decreased income taxes in NSPI as a
result of lower earnings 6.9 21.5
Deferral of Q1, 2005 taxes in NSPI pending
approval by the UARB - 15.3
Increased energy marketing margin as a result
of increased marketing opportunities and
mark-to-market gains on longer term contracts 4.2 1.7
Foreign exchange gains on US denominated financial
obligations; year over year includes a favourable
adjustment to refine prior years' foreign exchange 10.3 15.7
All other (3.6) (4.8)
-------------------------------------------------------------------------
Consolidated net earnings - 2005 $15.9 $83.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q3 basic earnings per share were $0.14 in 2005, compared to $0.20 in
2004; and $0.76 year to date in 2005, compared to $0.91 for the first nine
months of 2004.
NOVA SCOTIA POWER INC.
Overview
Electricity Rate Increase
On March 31, 2005, the UARB granted NSPI an average rate increase of
approximately 5.3%, effective April 1, 2005. The rate decision is expected to
increase NSPI's electric revenues by $30-$35 million in 2005 compared to 2004.
Other key aspects of the rate decision include:
- Rate of Return on Equity of 9.3 - 9.8% with rates set using 9.55%
(formerly 10.15%);
- Common Equity Component of 37.5% (formerly 35%); and
- Full recovery of $147 million Section 21 income tax deposit over eight
years, commencing in 2007.
The UARB expressed dissatisfaction with NSPI's fuel procurement practice.
The regulator disallowed $18 million of NSPI's forecasted 2005 fuel costs, and
rejected NSPI's settlement proposal to defer an additional $13 million to
2006. As a result, NSPI expects earnings for 2005 to be approximately
$22-$27 million lower than 2004, reflecting fuel costs that are substantially
higher than what has been provided for in rates, and the effect of the lower
allowed return on equity.
The UARB specified certain findings and directives concerning NSPI's fuel
procurement in its decision of March 31, 2005. On September 30, 2005, Nova
Scotia Power filed its final report with the UARB outlining changes it has
made to fuel procurement to comply with the UARB's findings.
2006 Rate Application
On July 5, 2005, Nova Scotia Power filed a general rate application
reflecting a request for an average 15% increase in electricity prices for
2006. Rising fuel prices are the key driver of the application. NSPI's fuel
expense is projected to be approximately $479 million in 2006 compared to
approximately $410 million in 2005, and the $359 million currently provided
for in rates.
The rate application also proposes an increase of $18.7 million in
operating expenses to improve customer service, strengthen network reliability
and to implement new conservation and energy efficiency measures.
Hearings are scheduled to begin November 14, 2005 with a decision
anticipated in Q1, 2006.
Review of Q3, 2005
NSPI Q3 Net Earnings
(millions of dollars, except Three months ended Nine months ended
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Electric revenue $221.5 $211.1 $712.1 $689.1
-------------------------------------------------------------------------
Fuel for generation and purchased
power 97.9 69.2 294.4 216.2
Operating, maintenance and general 47.6 41.9 140.2 131.1
Provincial grants and taxes 10.1 10.0 30.2 29.6
Provincial grants and taxes deferral - - (4.9) -
Depreciation 30.0 29.2 89.3 87.8
Regulatory amortization 1.6 1.6 4.7 4.7
Other (3.0) (3.0) (7.5) (7.9)
-------------------------------------------------------------------------
Earnings before interest and income
taxes 37.3 62.2 165.7 227.6
Interest 23.1 24.8 72.1 75.5
Amortization of defeasance costs 3.3 3.8 9.9 11.3
-------------------------------------------------------------------------
Earnings before income taxes 10.9 33.6 83.7 140.8
Income taxes 4.9 11.8 27.0 48.5
Income taxes deferral - - (10.4) -
-------------------------------------------------------------------------
Earnings before preferred dividends 6.0 21.8 67.1 92.3
Preferred dividends 3.3 3.3 9.9 10.0
-------------------------------------------------------------------------
Contribution to consolidated net
earnings $2.7 $18.5 $57.2 $82.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share $0.02 $0.17 $0.52 $0.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's net earnings were $2.7 million in Q3, 2005, compared to
$18.5 million in Q3, 2004. Year to date net earnings were $57.2 million in
2005 compared to $82.3 million in 2004. Highlights of the earnings changes
are summarized in the following table:
Three months Nine months
ended ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $18.5 $82.3
Increased electric revenue due to the 5.3% rate
increase effective April 1, 2005 10.4 23.0
Increased fuel expense due to higher commodity
prices and year to date reduced gas sales margin (28.7) (78.2)
Increased operating expenses reflecting increased
planned plant maintenance, storm costs, and
vegetation management costs (5.7) (9.1)
Decreased income taxes resulting from lower earnings 6.9 21.5
Deferral of Q1, 2005 taxes, pending approval by
the UARB - 15.3
All other 1.3 2.4
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $2.7 $57.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q3 Electric Sales Volume Q3 Electric Sales Revenues
(Gigawatt hours ("GWh")) (millions of dollars)
----------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
----------------------------------- ------------------------------------
Residential 783 802 730 Residential $85.1 $83.3 $76.1
Commercial 731 729 695 Commercial 63.8 61.8 61.1
Industrial 1,076 1,064 1,068 Industrial 61.2 56.3 58.5
Other 104 106 193 Other 11.4 9.7 15.3
----------------------------------- ------------------------------------
Total 2,694 2,701 2,686 Total $221.5 $211.1 $211.0
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
YTD Electric Sales Volume YTD Electric Sales Revenues
(GWh) (millions of dollars)
----------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
----------------------------------- ------------------------------------
Residential 3,001 2,986 2,770 Residential $307.2 $299.5 $272.9
Commercial 2,276 2,211 2,257 Commercial 198.3 192.0 188.8
Industrial 3,176 3,129 3,054 Industrial 176.6 167.3 165.1
Other 292 320 467 Other 30.0 30.3 37.6
----------------------------------- ------------------------------------
Total 8,745 8,646 8,548 Total $712.1 $689.1 $664.4
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Q3 Average Revenue/Megawatt hour ("MWh")
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Dollars per MWh $82 $78 $79
--------------------------------------------------------------
--------------------------------------------------------------
YTD Average Revenue/MWh
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Dollars per MWh $81 $80 $78
--------------------------------------------------------------
--------------------------------------------------------------
Electric revenues increased $10.4 million to $221.5 million in Q3, 2005
compared to $211.1 million in Q3, 2004. This reflects the April 1, 2005, 5.3%
rate increase approved by the UARB. Year to date electric revenues increased
$23.0 million to $712.1 million in 2005, compared to $689.1 million in 2004.
Fuel for Generation and Purchased Power
Q3 Production Volume
(GWh)
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Coal and petcoke 2,153 2,290 2,144
Natural gas 67 24 34
Oil 336 286 390
Renewable 146 99 175
Purchased power 120 122 113
--------------------------------------------------------------
Total 2,822 2,821 2,856
--------------------------------------------------------------
--------------------------------------------------------------
Purchased power includes 15 GWh of wind power in 2005.
YTD Production Volume
(GWh)
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Coal and petcoke 6,835 7,019 6,821
Natural gas 162 71 55
Oil 1,139 1,265 1,247
Renewable 755 624 804
Purchased power 404 300 264
--------------------------------------------------------------
Total 9,295 9,279 9,191
--------------------------------------------------------------
--------------------------------------------------------------
Purchased power includes 54 GWh of wind power in 2005.
Q3 Average Unit Fuel Costs
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Dollars per MWh $35 $25 $24
--------------------------------------------------------------
--------------------------------------------------------------
YTD Average Unit Fuel Costs
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Dollars per MWh $32 $23 $23
--------------------------------------------------------------
--------------------------------------------------------------
For the three months ended September 30, 2005, fuel for generation and
purchased power was $97.9 million, compared to $69.2 million in Q3, 2004. Year
to date fuel for generation and purchased power was $294.4 million in 2005
compared to $216.2 million in 2004. Highlights of the changes are summarized
in the following table:
Three months Nine months
ended ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2004 $69.2 $216.2
Increased commodity pricing including change in the
solid fuel mix to meet environmental requirements 25.8 62.8
Year to date lower gas sales margin due to reduced
volumes and higher pricing of supply contract,
offset by higher gas margin in the quarter (3.4) 14.4
Increased renewable energy production volumes (2.7) (9.5)
All other 9.0 10.5
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2005 $97.9 $294.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company's natural gas supply contract was subject to a contractual
price re-opener effective November 1, 2004, which will change the purchase
price. This contract is currently in binding arbitration. During the
arbitration period, the company continues to pay for gas purchases based on
the original contract pricing, but is recording the expense based on
management's best estimate of the new contract price. The difference is
included in Accounts Payable and Accrued Charges and will be paid to the
supplier once the arbitration is complete. The company expects a final
decision by Q1, 2006, which may result in a price different from management's
best estimate. Management is unable to predict the outcome of this arbitration
and the effect it may have on fuel for generation and purchased power expense,
financial results, cash flows or financial position.
In addition to the foregoing, the contract includes a price adjustment
clause covering the next three years of natural gas purchases. NSPI will pay
for all gas purchases at an estimated future contract price, but will be
entitled to a price rebate on a portion of the volume, to be settled in
November 2007. Again, management's best estimate of the price net of rebate is
included in fuel for generation and purchased power expense, with the
estimated rebate recorded in Deferred Charges and Other Receivables. There is
no right of offset for the two price adjustments.
Operating, Maintenance & General Expenses
NSPI's operating, maintenance and general expenditures ("OM&G") were
$47.6 million in Q3, 2005 compared to $41.9 million in Q3, 2004, primarily
reflecting increased plant maintenance costs, storm costs, and vegetation
management costs.
Year to date OM&G expenditures were $140.2 million compared to
$131.1 million for the same period in 2004. The increase reflects the items
noted above.
Provincial Grants and Taxes
The UARB agreed to allow NSPI to defer taxes not reflected in rates for
the period from January 1, 2005 until April 1, 2005, the date when new rates
became effective. In Q1, 2005, NSPI deferred $4.9 million of provincial grants
and taxes to March 31, 2005. The amount of the deferral and the amortization
period are pending approval by the UARB.
Interest
Interest expense decreased $1.7 million, to $23.1 million in Q3, 2005,
compared to $24.8 million in Q3, 2004, primarily due to the refinancing in
May 2005 of a $100 million 8.38% medium-term note with a $100 million 4.22%
medium-term note. In addition, NSPI had foreign exchange gains on its US
denominated financial liabilities. Year to date interest expense decreased
$3.4 million to $72.1 million from $75.5 million for the same period in 2004
due to the above and the refinancing of a $140 million medium-term note with
short-term debt in Q1, 2004.
Income Taxes
The UARB agreed to allow NSPI to defer taxes not reflected in rates for
the period January 1, 2005 until April 1, 2005, the date when new rates became
effective. In Q1, 2005, NSPI deferred $10.4 million of federal capital taxes
and income taxes reflecting increases in these taxes since rates were last set
in 2002. The amount of the deferral and the amortization period are pending
approval by the UARB.
NSPI has a $147 million regulatory asset related to pre-2003 income taxes
that have been paid, but not yet recovered from customers. This circumstance
arose when NSPI claimed deductions that were ultimately disallowed by a
decision of the Supreme Court of Canada. In its decision on NSPI's 2005 rate
application, the UARB has approved the amortization and recovery of this
regulatory asset over eight years, commencing in 2007.
Debt Management
On May 17, 2005, NSPI issued a $100 million medium-term note at a coupon
rate of 4.22% maturing May 17, 2010. The proceeds were used to refinance
$100 million 8.38% medium-term notes that matured on that date.
Outlook
As previously noted, NSPI expects earnings for 2005 to be approximately
$22-$27 million lower than 2004, primarily reflecting fuel costs that are
substantially higher than what has been provided for in rates. Actual earnings
to September 30, 2005 are $25.1 million lower year over year. NSPI expects its
fourth quarter 2005 net earnings to be in line with Q4, 2004 amounts because
higher fuel costs began to impact earnings in the fourth quarter of last year.
BANGOR HYDRO-ELECTRIC COMPANY
Since the restructuring of the electricity sector in Maine in 2000, BHE's
core business has been the transmission and distribution ("T&D") of
electricity. Electricity generation is deregulated in Maine, and several
suppliers compete to provide customers with the commodity that is delivered
through the BHE T&D network.
All amounts in the Bangor Hydro section are reported in US dollars unless
otherwise stated.
Review of Q3, 2005
Bangor Hydro Q3 Net Earnings
(millions of dollars, except Three months ended Nine months ended
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
T&D revenues $26.3 $28.9 $79.6 $86.7
Resale of purchased power 3.4 2.1 9.6 8.7
-------------------------------------------------------------------------
Total electric revenue 29.7 31.0 89.2 95.4
Purchased power and fuel for
generation 7.3 7.4 23.9 26.6
Operating, maintenance and general 7.2 7.6 23.5 23.0
Property taxes 1.4 1.2 4.1 3.7
Depreciation 3.0 2.6 9.2 7.8
Regulatory amortization 3.5 4.6 9.7 10.9
Other (1.1) (0.8) (3.1) (2.2)
-------------------------------------------------------------------------
Earnings before interest and income
taxes 8.4 8.4 21.9 25.6
Interest 2.4 2.4 7.4 7.8
-------------------------------------------------------------------------
Earnings before income taxes 6.0 6.0 14.5 17.8
Income taxes 2.4 2.4 5.6 7.2
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - US $ $3.6 $3.6 $8.9 $10.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - Canadian $ $4.4 $4.8 $10.9 $14.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated earnings
per common share - Canadian $ $0.04 $0.04 $0.10 $0.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted average foreign
exchange rate Canadian/US $ $1.22 $1.31 $1.22 $1.32
Bangor Hydro's contribution to consolidated net earnings was $3.6 million
in Q3, 2005, and Q3, 2004. Year to date, Bangor Hydro's contribution to
consolidated net earnings was $8.9 million, compared to $10.6 million in 2004.
Highlights of the earnings changes are summarized in the following table:
Three months Nine months
ended ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $3.6 $10.6
Increased residential and commercial energy sales 0.8 0.8
Increased NEPOOL related transmission expenses (0.3) (1.4)
Increased depreciation expense due to depreciation
study impacts (0.4) (1.4)
Write-off in Q2, 2004 of deferred costs disallowed
in rates - 1.1
All other (0.1) (0.8)
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $3.6 $8.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was $4.4 million
CAD in Q3, 2005 compared to $4.8 million CAD in Q3, 2004, due to the Canadian
dollar equivalent of the variances discussed above and the $0.4 million impact
of the stronger Canadian dollar. Year to date net earnings contributed by
Bangor Hydro was $10.9 million for 2005 compared to $14.1 million for 2004,
due to the Canadian dollar equivalent of the variances discussed above and the
$0.9 million impact of the stronger Canadian dollar.
Electric Revenue
Q3 T&D Sales Volume Q3 T&D Sales Revenues
(GWh) (millions of US dollars)
--------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
--------------------------------- ------------------------------------
Residential 146 138 127 Residential $12.2 $13.3 $12.3
Commercial 167 157 141 Commercial 9.2 10.9 9.8
Industrial 109 110 98 Industrial 3.6 3.7 3.7
Other 3 3 3 Other 1.3 1.0 0.8
--------------------------------- ------------------------------------
Total 425 408 369 Total $26.3 $28.9 $26.6
--------------------------------- ------------------------------------
--------------------------------- ------------------------------------
YTD T&D Sales Volume YTD T&D Sales Revenues
(GWh) (millions of US dollars)
--------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
--------------------------------- ------------------------------------
Residential 446 438 425 Residential $38.1 $41.4 $39.7
Commercial 463 453 436 Commercial 28.0 31.7 30.8
Industrial 304 257 270 Industrial 9.6 10.6 11.6
Other 9 9 9 Other 3.9 3.0 3.3
--------------------------------- ------------------------------------
Total 1,222 1,157 1,140 Total $79.6 $86.7 $85.4
--------------------------------- ------------------------------------
--------------------------------- ------------------------------------
Q3 Average Revenue / MWh
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Dollars per MWh $62 $71 $72
--------------------------------------------------------------
--------------------------------------------------------------
YTD Average Revenue / MWh
--------------------------------------------------------------
2005 2004 2003
--------------------------------------------------------------
Dollars per MWh $65 $75 $75
--------------------------------------------------------------
--------------------------------------------------------------
Electric revenues decreased by $2.6 million in Q3, 2005, to $26.3 million
compared to $28.9 million in Q3, 2004. Year to date, T&D electric revenues
were $79.6 million compared to $86.7 million for the same period. Highlights
of the changes are summarized in the following table:
Three months Nine months
ended ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
T&D revenues - 2004 $28.9 $86.7
Stranded cost rate reduction on March 1, 2005 (4.0) (9.5)
Increased residential and small commercial
energy sales 0.8 0.8
All other 0.6 1.6
-------------------------------------------------------------------------
T&D revenues - 2005 $26.3 $79.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Increases to industrial volumes year to date had a minimal impact on
sales revenues due to lower unit pricing.
Outlook
On February 25, 2005, the Maine Public Utilities Commission approved
changes to BHE's stranded cost rates for the three-year period March 1, 2005
to February 29, 2008. The stranded cost rates were reduced by approximately
37%, which represents an approximate 15% to 20% reduction in total electric
rates. The reduction is driven by the completion of a major regulatory
amortization, and increases in the rate at which BHE's power purchases under
long-term power supply agreements will be resold to a third party.
Accordingly, net earnings are expected to decrease only marginally.
In accordance with the provisions of BHE's Alternate Rate Plan ("ARP"),
BHE's distribution rates decreased by approximately 2.4% on July 1, 2005. BHE
anticipates managing the reduction to revenue with sales volume growth and
ongoing management of its operating, maintenance and general expenditures.
Regulatory Amortization
Amortization expense was $1.1 million lower in Q3, 2005 at $3.5 million,
compared to $4.6 million in Q3, 2004 reflecting new stranded cost
amortization, which started March 1, 2005.
Year to date amortization expense was $9.7 million in 2005, compared to
$10.9 million in 2004.
Regulatory Matters
When Emera acquired Bangor Hydro in 2001, it became a registered public
utility holding company under the Public Utility Holding Company Act of 1935
("PUHCA"). PUHCA is administered by the US Securities and Exchange Commission
("SEC"). In the normal course of regulating registered public utility holding
companies, the SEC audits and/or reviews each registrant's compliance with
PUHCA approximately once every five years. The SEC review of Emera began in
the fall of 2004. By letter dated September 25, 2005 the staff of the SEC
indicates that Emera is in compliance with PUHCA, pending reallocation of
certain costs among companies in the Emera group. The proposed reallocations
are not material to Emera or any individual Emera subsidiary.
PUHCA has been repealed, effective February 8, 2006, under the Domenici-
Barton Energy Policy Act of 2005. As of that date, Emera will cease to be
regulated as a registered holding company under PUHCA. The Energy Policy Act
lodged certain new powers over companies that own electric and gas public
utility companies with the US FERC.
Outlook
The Northeast Reliability Interconnect ("NRI"), Bangor Hydro's proposed
new transmission line linking New Brunswick and Maine, achieved a significant
milestone in Q3, 2005, with the receipt of its Certificate of Public
Convenience and Necessity from the Maine Public Utilities Commission. BHE is
now focusing on securing the outstanding environmental permits from the State
and Federal Governments, and continues to expect to have the line in service
in late 2007.
OTHER
All activities of Emera other than its two regulated electric utilities
are incorporated in Other, including:
- Emera Energy Services, which manages energy assets on behalf of third
parties and provides related energy management services. Emera Energy
Services operates with minimal day-to-day commodity risk exposure.
- A 12.9% interest in the $2 billion, 1,300 kilometre Maritimes &
Northeast Pipeline ("M&NP") that transports Nova Scotia's offshore
natural gas to markets in Maritime Canada and the northeastern United
States.
- Bear Swamp, a 50-50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts, which was acquired
on May 24, 2005.
- Emera Fuels, an unregulated subsidiary that distributes home heating
oil, heavy fuel oil, lubricants and related products to over 22,000
customers in the Maritime provinces. As discussed below, Emera
divested itself of the assets of Emera Fuels in Q3, 2005.
- Certain corporate-wide functions such as executive management,
strategic planning, treasury services, tax planning, business
development, and corporate governance; and financing for the
corporation's business outside of its regulated electric utilities.
Sale of Assets of Emera Fuels
Effective September 30, 2005 Emera sold its heating oil distribution
business for proceeds of $18.6 million, which will be used to pay down debt. A
loss on disposition of $1.6 million after-tax was recognized in Q3, 2005. The
transaction will reduce Emera's total assets by approximately $25 million (net
assets by approximately $20 million). The reduction in annual after-tax net
earnings and cash provided by operating activities is expected to be minimal.
Acquisition
On May 24, 2005 Emera and Brascan Power Inc., in a 50-50 joint venture,
completed the acquisition of Bear Swamp, a 600 MW pumped storage hydro-
electric facility in northern Massachusetts. Emera's share of the purchase
price was $61.0 million including acquisition costs. The facility sells
energy, capacity and ancillary products to the New England Power Pool. Also
included in the acquisition is the nearby 10 MW Fife Brook run-of-river
hydro-electric facility.
The acquisition has been accounted for under the purchase method of
accounting using proportionate consolidation, and accordingly, the results of
operations since the date of acquisition have been included in the
consolidated statement of earnings and the summary statement of earnings
below.
The 50-50 joint venture partnership between Emera and Brascan Power Inc.
has not received the required regulatory approval at this time to proceed with
the lease agreement of the 49 MW Bellows Falls hydro-electric facility. Emera
was required to place its full share of the lease amount in escrow, pending
completion of the transaction. The funds remain in escrow pending the
resolution of the matters concerning the transaction.
Review of Q3, 2005
Other Q3 Net Earnings
(millions of dollars, except Three months ended Nine months ended
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Energy marketing margin $8.1 $3.9 $19.2 $17.5
Equity earnings 1.5 1.4 4.8 5.0
Electric revenue 3.6 - 5.5 -
-------------------------------------------------------------------------
Total revenue 13.2 5.3 29.5 22.5
Operating, maintenance and general 6.3 5.4 16.3 15.7
Business development 0.6 1.3 1.1 5.2
Depreciation 0.5 0.3 1.3 0.8
Other (2.0) (1.1) (4.1) (4.0)
-------------------------------------------------------------------------
Earnings before interest and
income taxes 7.8 (0.6) 14.9 4.8
Interest (3.4) 3.3 (2.1) 10.3
-------------------------------------------------------------------------
Earnings before income taxes 11.2 (3.9) 17.0 (5.5)
Income taxes 0.2 (2.6) 0.7 (6.0)
-------------------------------------------------------------------------
Net earnings from continuing
operations 11.0 (1.3) 16.3 0.5
Loss on disposition, net of tax (1.6) - (1.6) -
Earnings from discontinued
operations, net of tax (0.6) 0.1 0.7 1.5
-------------------------------------------------------------------------
Contribution to consolidated net
earnings $8.8 $(1.2) $15.4 $2.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share $0.08 $(0.01) $0.14 $0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The contribution of Other operations to consolidated net earnings
increased $10.0 million quarter over quarter and increased $13.4 million year
to date 2005 compared to 2004. Highlights of the changes are summarized in the
following table:
Three months Nine months
ended ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $(1.2) $2.0
Increased energy marketing margin as a result
of increased marketing opportunities and
mark-to-market gains on longer term contracts 4.2 1.7
Addition of Bear Swamp hydro-electric facility
earnings before interest & taxes 2.2 2.6
Foreign exchange gains on US denominated
financial obligations; year over year includes
a favourable adjustment to refine prior years'
foreign exchange 9.0 14.6
Higher income taxes due to higher earnings (2.8) (6.7)
Loss on disposition of Emera Fuels, net of tax (1.6) (1.6)
Write-off of Greyhawk Gas Storage joint venture
in Q1, 2004 - 1.9
All other (1.0) 0.9
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $8.8 $15.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Energy Marketing Margin
Emera Energy Services net margin increased quarter over quarter to
$8.1 million in Q3, 2005, from $3.9 million in Q3, 2004 as a result of
increased marketing opportunities and mark-to-market gains on longer term
contracts. Year to date net margin was $19.2 million compared to $17.5 million
in the previous year for these same reasons.
Equity Earnings
Equity earnings from the Maritimes & Northeast Pipeline were $1.5 million
in Q3, 2005, compared to $1.4 million for the same period in 2004. Year to
date equity earnings were $4.8 million in 2005 compared to $5.0 million in
2004. Increases in the tolls collected for the US operations have been offset
by the write off of previously deferred costs for pipeline expansion on the US
pipeline, and the impact of the stronger Canadian dollar on the US portion of
the pipeline.
In 2004 Maritimes & Northeast Pipeline filed a Notice of Rate Increase
for its US operations. The changes reflected in the filing result principally
from:
- A decline in reserves and deliverability associated with the Sable
Offshore Energy Project fields;
- The inclusion in the rates of costs related to the Phase III expansion
project M&NP placed into service on November 24, 2003; and
- An updated cost of service study.
Effective January 1, 2005 M&NP was permitted to collect proposed rates
from customers, pending approval of new rates. In the event approved rates are
lower than proposed, any excess will be returned to customers. On June 28,
2005 M&NP submitted an offer of settlement to the FERC. In Q3, 2005 the
company recognized its best estimate of $0.3 million (year to date -
$3.3 million) in equity earnings and energy marketing margin in Emera Energy
Services based on the terms of the proposed settlement. The decision from the
FERC is expected by Q1, 2006.
Electric Revenue
Electric revenue represents Emera's share of electric revenue from Bear
Swamp since the date of acquisition on May 24, 2005.
Business Development
Business development costs were $0.6 million in Q3, 2005, compared to
$1.3 million in Q3, 2004.
Year to date business development costs were $1.1 million compared to
$5.2 million for the same period in 2004, reflecting the write-off in Q1, 2004
of Emera's $1.9 million investment in the Greyhawk Gas Storage joint venture,
a portion of which was subsequently recovered in Q1, 2005; the business
development expenses capitalized as part of the Bear Swamp acquisition and
more focused business development activity in 2005.
Interest
Interest expense was $(3.4) million in Q3, 2005 compared to $3.3 million
in Q3, 2004 largely as a result of the translation impact of a stronger
Canadian dollar on the company's US dollar denominated financial obligations.
Year to date interest was $(2.1) million in 2005 compared to $10.3 million in
2004 due to the same reason, and a favorable adjustment required to refine
prior years' foreign exchange recognized on US denominated obligations.
Consolidated Balance Sheets
Significant changes in the consolidated balance sheets between
September 30, 2005 and December 31, 2004 include:
- $25.9 million increase in restricted cash, reflecting posted margin
received from a counterparty in Nova Scotia Power and a deposit
received from a standard offer supplier in Bangor Hydro.
- $75.9 million increase in accounts receivable, reflecting an increase
in rates and a decrease in the amount of accounts receivable
securitized in NSPI, increased prices in Emera Energy Services, and
the proceeds receivable on the disposition of the company's heating
oil distribution business.
- $17.7 million increase in income tax receivable, reflecting a lower
tax provision in NSPI due to lower earnings, and future income taxes
in Emera Energy Services that have become a current receivable in
2005.
- $16.5 million increase in inventory reflecting an increase in coal
inventory levels and higher commodity prices.
- $10.4 million increase in prepaid expenses, reflecting the timing of
the payment of the provincial grants in lieu.
- $30.4 million increase in energy marketing assets reflecting increased
market opportunities and mark-to-market gains on longer term
contracts.
- $11.0 million decrease in goodwill, largely reflecting the disposition
of the company's heating oil distribution business.
- $41.1 million increase in capital assets, reflecting the acquisition
of the Bear Swamp hydro-electric facility in northern Massachusetts.
- $95.2 million increase in accounts payable and accrued charges,
reflecting the increase in fuel related payables due to the
arbitration of a supply contract and increased posted margin from
counterparties offset by the timing of payments in NSPI, increased
prices in Emera Energy Services, and a deposit received in Bangor
Hydro from a standard offer provider.
- $25.7 million increase in energy marketing liabilities reflecting
increased marketing opportunities and mark-to-market gains on longer
term contracts.
Outstanding Share Data
Common
Issued and Outstanding: Millions of Share
(millions of dollars) Shares Capital
-------------------------------------------------------------------------
January 1, 2004 108.26 $1,008.4
Issued for cash under purchase plans 0.41 7.0
Options exercised under senior management share
option plan 0.20 2.8
Share-based compensation - 1.0
-------------------------------------------------------------------------
December 31, 2004 108.87 $1,019.2
Issued for cash under purchase plans 0.32 5.8
Options exercised under senior management share
option plan 0.69 11.1
Share-based compensation - 0.7
-------------------------------------------------------------------------
September 30, 2005 109.88 $1,036.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liquidity and Capital Resources
On July 5, 2005, Standard & Poor's Rating Services revised its outlook
for Emera and Nova Scotia Power to negative from stable citing fuel cost
recovery concerns. On July 6, 2005 the Dominion Bond Rating Service ("DBRS")
confirmed Emera and NSPI's ratings as BBB (high) and A (low) respectively.
NSPI's commercial paper rating was confirmed at R-1 (Low). On October 11,
2005, Moody's Investors Services revised its outlook on Emera and Nova Scotia
Power from stable to negative citing fuel cost recovery and regulatory
uncertainty.
In Q1, 2005 Emera and Nova Scotia Power established debt shelf
prospectuses in the amounts of $300 million and $400 million respectively that
provide the companies with access to long-term debt. The prospectuses expire
in April 2007. In May, 2005 NSPI issued a $100 million medium term note,
refinancing a $100 million maturity due that same month.
In July, 2005 NSPI's Board of Directors approved an increase to the size
of its commercial paper program from $350 million to $400 million. The
company's banking syndicate provides 100% backup facility for this program.
Consolidated Cash Flow Highlights
Three months ended Nine months ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Net cash provided by operating
activities $116.7 $93.8 $200.6 $241.7
Net cash used in financing
activities (46.5) (28.3) (48.4) (118.1)
Net cash used in investing
activities (83.7) (58.9) (175.7) (109.0)
-------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents $(13.5) $6.6 $(23.5) $14.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash provided by operating activities was $116.7 million
in Q3, 2005, compared to $93.8 million in Q3, 2004 reflecting the receipt of
posted margin in the quarter. Increases in posted margin are offset by
increases in restricted cash, which are included in investing activities
below. Year to date consolidated net cash provided by operating activities was
$200.6 million in 2005 compared to $241.7 million in 2004 reflecting increased
fuel costs and the outstanding proceeds related to the disposition of Emera
Fuels, offset somewhat by the increase in posted margin.
Consolidated net cash used in financing activities increased
$18.2 million in Q3, 2005, compared to Q3, 2004 reflecting lower cash
requirements in the quarter. Year to date net cash used in financing
activities decreased $69.7 million year to date 2005 compared to 2004,
reflecting higher consolidated debt levels in order to fund the acquisition of
Bear Swamp and higher fuel costs in NSPI.
Consolidated net cash used in investing activities increased
$24.8 million in the quarter over prior year reflecting increases in
restricted cash related to posted margin offset to some extent by lower
overall capital spending. Year to date cash used in investing activities
increased $66.7 million due primarily to the acquisition of the Bear Swamp
hydro electric facility and increases in restricted cash related to posted
margin, offset somewhat by reduced capital spending.
Financial and Commodity Instruments
The company manages its exposure to foreign exchange, interest rate, and
commodity risks in accordance with established risk management policies and
procedures. The company uses derivative instruments consisting mainly of
foreign exchange forward contracts, interest options and swaps, and oil and
gas options and swaps.
Instruments that meet stringent documentation requirements, and can be
proven to be effective both at the inception and over the term of the
instrument qualify for hedge accounting. Specifically, amounts paid or
received are deferred and recognized in earnings in the same period the
related hedged item is realized. Where the documentation or effectiveness
requirements are not met, the non-qualifying instruments are marked-to-market
and recognized in earnings in the reporting period.
The company has deferred payments and receipts on derivative instruments
that are designated and effective as hedges and are recognized in the
following categories in the balance sheet:
Deferred Hedging Losses (Gains) Recognized on the Balance Sheet
(millions of dollars)
-------------------------------------------------------------------------
September 30 December 31
2005 2004
-------------------------------------------------------------------------
Inventory $0.5 $1.6
Deferred charges - 0.1
Accounts payable and accrued charges (0.1) (0.3)
-------------------------------------------------------------------------
Deferred hedging losses $0.4 $1.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three month and nine month periods ended September 30, the
impacts of effective hedges recognized in earnings were recorded in the
following categories:
Hedging Impact Recognized in Earnings
Three months ended Nine months ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Fuel and purchased power decrease
(increase) $(8.7) $1.6 $(16.6) $(3.5)
Interest expense increase (0.5) (1.2) (1.5) (4.7)
-------------------------------------------------------------------------
Hedging earnings impact $(9.2) $0.4 $(18.1) $(8.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company also enters into non-hedging derivative financial and
commodity instruments. These instruments, along with the non-qualifying hedges
referred to above, are marked-to-market at each reporting date.
The company had recorded the following mark-to-market transactions
included in the balance sheet and recognized in earnings.
Mark-to-Market Gains (Losses) Recognized on the Balance Sheet
(millions of dollars)
-------------------------------------------------------------------------
September 30 December 31
2005 2004
-------------------------------------------------------------------------
Energy marketing assets $40.7 $10.3
Energy marketing liabilities (35.1) (9.4)
Deferred credits (0.4) -
-------------------------------------------------------------------------
Mark-to-market gains $5.2 $0.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Mark-to-Market Gains (Losses) Recognized in Earnings
Three months ended Nine months ended
(millions of dollars) September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Other revenue $3.8 $(0.1) $5.1 $0.1
Fuel and purchased power - 4.6 - 3.3
Interest (0.4) - (0.4) -
-------------------------------------------------------------------------
Mark-to-market gains $3.4 $4.5 $4.7 $3.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In determining the fair value of derivative financial instruments, the
company has relied on quoted market prices as at the reporting date.
Transactions With Related Parties
In the ordinary course of business, Emera purchased natural gas
transportation capacity totaling $9.9 million (2004 - $11.5 million) during
the three months ended September 30, 2005, and $30.0 million (2004 -
$35.3 million) during the nine months ended September 30, 2005, from the
Maritimes & Northeast Pipeline, an investment under significant influence of
the company. The amount is recognized in fuel for generation and purchased
power or netted against energy marketing margin in other revenue, and is
measured at the exchange amount. At September 30, 2005 the amount payable to
the related party is $3.3 million (December 31, 2004 - $3.2 million), is
non-interest bearing and is under normal credit terms.
Change in Accounting Policies
Variable Interest Entities
In June 2003, the Canadian Institute of Chartered Accountants issued
Accounting Guideline 15 Consolidation of Variable Interest Entities. This
guideline applies to annual and interim periods beginning on or after
November 1, 2004. A variable interest entity ("VIE") is any type of legal
structure in which control is determined through contractual or other
financial arrangements as opposed to traditional voting rights, if certain
conditions exist. The guideline requires the enterprise which absorbs the
majority of a VIE's expected losses or receives the majority of a VIE's
expected residual returns, the primary beneficiary, to consolidate the VIE.
The company has variable interests in VIEs that are not consolidated
because the company is not considered the primary beneficiary. These variable
interests consist of purchase power agreements for renewable energy with
independent power producers. The company's only obligation under these
agreements is to purchase all of the energy produced, which currently is
expected to approximate 100 GWh annually.
Summary of Quarterly Reports
For the quarter ended
(millions of dollars, except earnings per common share)
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
2005 2005 2005 2004 2004 2004 2004 2003
-------------------------------------------------------------------------
Total revenues $273.9 $275.5 $309.7 $284.5 $260.1 $268.8 $318.8 $289.8
Net earnings
applicable to
common shares $15.9 $19.3 $48.3 $31.4 $22.1 $29.8 $46.5 $47.5
Earnings per
common share
- basic $0.14 $0.18 $0.44 $0.30 $0.20 $0.27 $0.43 $0.44
Earnings per
common share
- diluted $0.14 $0.18 $0.42 $0.28 $0.20 $0.27 $0.41 $0.43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Quarterly total revenues and net earnings applicable to common shares are
affected by seasonality, with Q1 and Q4 the strongest periods, reflecting
colder weather and fewer daylight hours at those times of year.
Financial Statements
Consolidated Statements of Earnings (Unaudited)
For the
(millions of dollars, except earnings per common share)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Revenue
Electric $260.8 $252.0 $826.8 $818.8
Other (note 15) 13.1 8.1 32.3 28.9
-------------------------------------------------------------------------
273.9 260.1 859.1 847.7
-------------------------------------------------------------------------
Cost of operations
Fuel for generation and
purchased power
(notes 11 & 15) 106.5 78.9 323.5 253.0
Operating, maintenance, and
general 63.1 58.5 186.3 182.6
Provincial, state, and
municipal taxes 12.2 11.8 36.6 34.9
Provincial tax deferral
(note 10) - - (4.9) -
Depreciation 34.1 32.9 101.9 98.9
-------------------------------------------------------------------------
215.9 182.1 643.4 569.4
-------------------------------------------------------------------------
Earnings from operations 58.0 78.0 215.7 278.3
Equity earnings (notes 8 & 16) 1.5 1.4 4.8 5.0
Regulatory amortization (5.7) (7.7) (16.5) (19.3)
Allowance for funds used
during construction 1.4 1.0 3.4 2.4
-------------------------------------------------------------------------
Earnings before interest and
income taxes 55.2 72.7 207.4 266.4
Interest (note 9) 22.6 31.3 79.0 96.3
Amortization of defeasance costs 3.3 3.8 9.9 11.3
-------------------------------------------------------------------------
Earnings before income taxes 29.3 37.6 118.5 158.8
Income taxes 7.9 12.3 34.5 51.9
Income taxes deferral (note 10) - - (10.4) -
-------------------------------------------------------------------------
Net earnings before
non-controlling interest 21.4 25.3 94.4 106.9
Non-controlling interest (note 14) 3.3 3.3 10.0 10.0
-------------------------------------------------------------------------
Net earnings from continuing
operations 18.1 22.0 84.4 96.9
Loss on disposition, net of tax
(note 4) (1.6) - (1.6) -
Earnings from discontinued
operations, net of tax (note 4) (0.6) 0.1 0.7 1.5
-------------------------------------------------------------------------
Net earnings applicable to
common shares $15.9 $22.1 $83.5 $98.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - basic
Continuing operations $0.16 $0.20 $0.77 $0.90
Discontinued operations (0.02) - (0.01) 0.01
-------------------------------------------------------------------------
$0.14 $0.20 $0.76 $0.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - diluted
Continuing operations $0.16 $0.20 $0.77 $0.87
Discontinued operations (0.02) - (0.01) 0.01
-------------------------------------------------------------------------
$0.14 $0.20 $0.76 $0.88
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Weighted average number of
common shares outstanding
(millions)
- basic 109.7 108.5 109.4 108.5
- diluted 109.7 108.5 109.4 122.9
Consolidated Statements of Retained Earnings (Unaudited)
For the nine months ended September 30
(millions of dollars)
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Retained earnings, beginning of year $399.6 $365.3
Net earnings applicable to common shares 83.5 98.4
-------------------------------------------------------------------------
483.1 463.7
Dividends 72.9 71.5
-------------------------------------------------------------------------
Retained earnings, end of period $410.2 $392.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Consolidated Balance Sheets (Unaudited)
As at
(millions of dollars)
-------------------------------------------------------------------------
September 30 December 31
2005 2004
-------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $19.2 $42.7
Restricted cash 44.1 18.2
Accounts receivable 252.0 176.1
Income tax receivable 20.1 2.4
Inventory 89.9 73.4
Prepaid expenses 15.8 5.4
Future income tax assets 9.0 3.6
Energy marketing assets 37.2 10.3
-------------------------------------------------------------------------
487.3 332.1
-------------------------------------------------------------------------
Long-term receivable 20.0 20.0
-------------------------------------------------------------------------
Energy marketing assets 3.5 -
-------------------------------------------------------------------------
Deferred charges and other receivables (note 11) 573.4 580.2
-------------------------------------------------------------------------
Future income tax assets 19.7 34.1
-------------------------------------------------------------------------
Goodwill 96.7 107.7
-------------------------------------------------------------------------
Investments (note 12) 99.1 96.8
-------------------------------------------------------------------------
Property, plant and equipment 2,767.4 2,714.6
Construction work in progress 52.0 63.7
-------------------------------------------------------------------------
2,819.4 2,778.3
-------------------------------------------------------------------------
$4,119.1 $3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Current portion of long-term debt $152.5 $100.8
Short-term debt 334.6 145.4
Accounts payable and accrued charges 328.6 233.4
Income tax payable 2.0 1.4
Dividends payable 3.2 3.2
Energy marketing liabilities 34.4 9.4
-------------------------------------------------------------------------
855.3 493.6
-------------------------------------------------------------------------
Energy marketing liabilities 0.7 -
-------------------------------------------------------------------------
Future income tax liabilities 78.5 82.2
-------------------------------------------------------------------------
Asset retirement obligations 70.5 68.5
-------------------------------------------------------------------------
Deferred credits 77.6 80.8
-------------------------------------------------------------------------
Long-term debt (note 13) 1,427.4 1,626.5
-------------------------------------------------------------------------
Non-controlling interest (note 14) 260.8 260.8
-------------------------------------------------------------------------
Shareholders' equity
Common shares (note 14) 1,036.8 1,019.2
Foreign exchange translation adjustment (98.7) (82.0)
Retained earnings 410.2 399.6
-------------------------------------------------------------------------
1,348.3 1,336.8
-------------------------------------------------------------------------
$4,119.1 $3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contingencies (Note 16)
See accompanying notes to the unaudited consolidated financial
statements.
Approved on behalf of the Board of Directors
Derek Oland Christopher Huskilson
Chairman President and Chief Executive Officer
Consolidated Statements of Cash Flow (Unaudited)
For the
(millions of dollars)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Operating activities
Net earnings before
non-controlling interest $21.4 $25.3 $94.4 $106.9
Non-cash items:
Depreciation 34.1 32.9 101.9 98.9
Deferral of provincial taxes
and income taxes - - (15.3) -
Amortization of deferred charges 8.5 7.2 23.2 26.4
Equity earnings (1.5) (1.4) (4.8) (5.0)
Regulatory amortization 5.7 7.7 16.5 19.3
Allowance for funds used during
construction (1.4) (1.0) (3.4) (2.4)
Future income taxes 2.7 (5.0) 9.8 (12.3)
Discontinued operations 0.3 0.1 2.1 2.0
Other cash operating items (8.6) (3.7) (16.9) (1.4)
-------------------------------------------------------------------------
61.2 62.1 207.5 232.4
Change in non-cash operating
working capital 55.5 31.7 (6.9) 9.3
-------------------------------------------------------------------------
Net cash provided by operating
activities 116.7 93.8 200.6 241.7
-------------------------------------------------------------------------
Financing activities
Retirements of long-term debt - (1.2) (102.3) (165.3)
Issuance of long-term debt - - 100.0 -
Increase (decrease) in
short-term debt (5.5) (4.7) 51.1 121.5
Issuance of common shares 4.0 3.4 16.9 7.8
Dividends on common shares (24.4) (23.8) (72.9) (71.5)
Dividends paid by subsidiaries
to non-controlling interest (3.3) (3.5) (10.0) (10.6)
Accounts receivable
securitization (20.0) - (30.0) -
Other financing 2.7 1.5 (1.2) -
-------------------------------------------------------------------------
Net cash used in financing
activities (46.5) (28.3) (48.4) (118.1)
-------------------------------------------------------------------------
Investing activities
Property, plant and equipment (39.3) (61.8) (92.9) (108.6)
Proceeds on disposition (note 4) 0.1 - 0.1 -
Acquisition (note 5) - - (52.6) -
Retirement spending net of
salvage (1.2) (0.6) (2.9) (1.3)
Proceeds from sale of assets - - - 0.8
Decrease (increase) in
restricted cash (43.3) 3.5 (25.9) 1.0
Other investing activities - - (1.5) (0.9)
-------------------------------------------------------------------------
Net cash used in investing
activities (83.7) (58.9) (175.7) (109.0)
-------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents (13.5) 6.6 (23.5) 14.6
Cash and cash equivalents,
beginning of period 32.7 18.0 42.7 10.0
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $19.2 $24.6 $19.2 $24.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents
consists of:
Cash $18.4 $23.2 $18.4 $23.2
Cash equivalents 0.8 1.4 0.8 1.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $19.2 $24.6 $19.2 $24.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental disclosure of cash
paid:
Interest $36.3 $34.5 $97.4 $101.7
Income and capital taxes $15.8 $18.4 $48.9 $65.3
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Notes to the Interim Unaudited Consolidated Financial Statements
September 30, 2005
1. Basis of Presentation
The disclosures in these unaudited interim consolidated financial
statements do not conform in all respects to the requirements of
Canadian Generally Accepted Accounting Principles for annual audited
financial statements and should be read in conjunction with Emera
Inc.'s annual consolidated financial statements as at and for the
year ended December 31, 2004.
These consolidated financial statements follow the same accounting
policies and methods of computation as Emera Inc.'s annual audited
consolidated financial statements as at and for the year ended
December 31, 2004 with the exception of the accounting policy change
disclosed in note 3.
2. Seasonal Nature of Operations
Interim results are not necessarily indicative of results for the
full year due primarily to seasonal factors. Sales and related
production change significantly over the year, with Q1 and Q4, the
strongest periods, reflecting colder weather and fewer daylight hours
in the winter season.
3. Change in Accounting Policies
Variable Interest Entities
In June 2003, the Canadian Institute of Chartered Accountants
("CICA") issued Accounting Guideline 15 Consolidation of Variable
Interest Entities. This guideline applies to annual and interim
periods beginning on or after November 1, 2004. A variable interest
entity ("VIE") is any type of legal structure in which control is
determined through contractual or other financial arrangements as
opposed to traditional voting rights, if certain conditions exist.
The guideline requires the enterprise which absorbs the majority of a
VIE's expected losses or receives the majority of a VIE's expected
residual returns, the primary beneficiary, to consolidate the VIE.
The Company has variable interests in VIEs that are not consolidated
because the Company is not considered the primary beneficiary. These
VIEs include purchase power agreements for renewable energy with
independent power producers. The Company's only obligation under
these agreements is to purchase all of the energy produced, which
currently is expected to approximate 100 GWh annually.
4. Discontinued Operations
Effective September 30, 2005 Emera Fuels, a subsidiary of Emera, sold
its heating oil distribution business. Emera Fuels is included in
the segment "Other" in Note 6 Segment Information.
Emera Fuels has been accounted for as discontinued operations.
Accordingly, prior periods have been reclassified to reflect this
change. The following provides additional information with respect to
amounts included in earnings from discontinued operations on the
consolidated statements of earnings:
---------------------------------------------------------------------
For the Three months ended Nine months ended
(millions of dollars) September 30 September 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Revenue $19.1 $15.9 $69.7 $62.9
Earnings before income taxes $(0.9) $(0.4) $0.3 $1.1
---------------------------------------------------------------------
---------------------------------------------------------------------
The following summarizes the transaction:
(millions of dollars)
---------------------------------------------------------------------
Proceeds on disposition $18.6
Disposition costs 0.2
---------------------------------------------------------------------
Net proceeds on disposition 18.4
Net assets included in disposition 19.3
---------------------------------------------------------------------
Loss on disposition 0.9
Income taxes 0.7
---------------------------------------------------------------------
Loss on disposition, net of tax $1.6
---------------------------------------------------------------------
---------------------------------------------------------------------
Proceeds will be received in Q4, 2005.
5. Acquisition
On May 24, 2005 Emera and Brascan Power Inc., in a 50-50 joint
venture, acquired Bear Swamp, a 600 megawatt ("MW") pumped storage
hydro-electric facility in northern Massachusetts. Emera's share of
the purchase price was $61.0 million. The facility sells energy,
capacity and ancillary products to the New England Power Pool. Also
included in the acquisition is the nearby 10 MW Fife Brook
run-of-river hydro-electric facility.
The acquisition has been accounted for under the purchase method of
accounting using proportionate consolidation, and accordingly, the
results of operations since the date of acquisition have been
included in the consolidated statement of earnings.
Emera's share of the transaction is summarized as follows:
Net Assets Acquired (millions of dollars)
---------------------------------------------------------------------
Property, plant and equipment $60.7
Construction work in progress 0.3
---------------------------------------------------------------------
Total cash consideration $61.0
---------------------------------------------------------------------
---------------------------------------------------------------------
6. Segment Information
Segmented financial information for the three months ended and as at
September 30, 2005:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $223.8 $36.6 $13.5 $273.9
Depreciation 30.0 3.6 0.5 34.1
Cost of operations, including
depreciation 185.6 22.7 7.6 215.9
Net intersegment operating
revenues/(expenses) 51.9 (0.6) (51.3) -
Equity earnings - - 1.5 1.5
Interest expense 23.1 2.9 (3.4) 22.6
Income taxes 4.9 2.8 0.2 7.9
Net earnings from continuing
operations 2.7 4.4 11.0 18.1
Net earnings applicable to
common shares 2.7 4.4 8.8 15.9
Assets 3,082.4 593.6 443.1 4,119.1
Goodwill - 96.7 - 96.7
Goodwill included in loss
on disposition - - 7.4 7.4
Capital expenditures 30.8 8.4 0.1 39.3
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented financial information for the three months ended and as at
September 30, 2004:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $213.4 $41.6 $5.1 $260.1
Depreciation 29.2 3.4 0.3 32.9
Cost of operations, including
depreciation 150.3 24.6 7.2 182.1
Net intersegment operating
revenues/(expenses) 31.9 (0.5) (31.4) -
Equity earnings - - 1.4 1.4
Interest expense 24.8 3.2 3.3 31.3
Income taxes 11.8 3.1 (2.6) 12.3
Net earnings from continuing
operations 18.5 4.8 (1.3) 22.0
Net earnings applicable to
common shares 18.5 4.8 (1.2) 22.1
Assets 2,982.2 633.7 268.7 3,884.6
Goodwill - 105.3 7.4 112.7
Capital expenditures 48.4 13.7 - 62.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented financial information for the nine months ended and as at
September 30, 2005:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $717.8 $111.6 $29.7 $859.1
Depreciation 89.3 11.3 1.3 101.9
Cost of operations, including
depreciation 549.2 74.4 19.8 643.4
Net intersegment operating
revenues/(expenses) 117.0 (1.9) (115.1) -
Equity earnings - - 4.8 4.8
Interest expense 72.1 9.0 (2.1) 79.0
Income taxes 27.0 6.8 0.7 34.5
Net earnings from continuing
operations 57.2 10.9 16.3 84.4
Net earnings applicable to
common share 57.2 10.9 15.4 83.5
Assets 3,082.4 593.6 443.1 4,119.1
Goodwill - 96.7 - 96.7
Goodwill included in loss on
disposition - - 7.4 7.4
Capital expenditures 70.8 23.4 51.3 145.5
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented financial information for the nine months ended and as at
September 30, 2004:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $694.8 $129.5 $23.4 $847.7
Depreciation 87.8 10.3 0.8 98.9
Cost of operations, including
depreciation 464.7 81.2 23.5 569.4
Net intersegment operating
revenues/(expenses) 119.3 (1.3) (118.0) -
Equity earnings - - 5.0 5.0
Interest expense 75.5 10.5 10.3 96.3
Income taxes 48.5 9.4 (6.0) 51.9
Net earnings from continuing
operations 82.3 14.1 0.5 96.9
Net earnings applicable to
common shares 82.3 14.1 2.0 98.4
Assets 2,982.2 633.7 268.7 3,884.6
Goodwill - 105.3 7.4 112.7
Capital expenditures 106.4 23.8 (21.6) 108.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(x) Other consists of items related to corporate activities and other
subsidiaries.
7. Employee Future Benefits
Emera maintains contributory defined-benefit and defined-contribution
pension plans, which cover substantially all of its employees, and
plans that provide non-pension benefits for its retirees. The
Company's cost, related to these plans, for the three month period
ended September 30, 2005 is $7.6 million (2004 - $6.5 million), and
for the nine month period ended September 30, 2005 is $22.2 million
(2004 - $20.3 million).
8. Equity Earnings
Equity earnings of $1.5 million (2004 - $1.4 million) for the three
months ended September 30, 2005, and $4.8 million (2004 -
$5.0 million) for the nine months ended September 30, 2005, consists
of the Company's pro-rata portion of after-tax earnings from
Maritimes and Northeast Pipeline, an investment under significant
influence of the Company.
9. Interest
Interest expense consists of the following:
Three months ended Nine months ended
September 30 September 30
---------------------------------------------------------------------
(millions of dollars) 2005 2004 2005 2004
---------------------------------------------------------------------
Interest on long-term debt $25.7 $27.1 $78.9 $84.0
Interest on short-term debt 5.7 2.6 12.4 9.0
Amortization of debt financing 0.4 0.5 1.4 1.3
Foreign exchange losses (gains) (9.2) 1.1 (13.7) 2.0
---------------------------------------------------------------------
$22.6 $31.3 $79.0 $96.3
---------------------------------------------------------------------
---------------------------------------------------------------------
10. Provincial Tax Deferral and Income Tax Deferral
The UARB agreed to allow NSPI to defer taxes not reflected in rates
for the period January 1, 2005 until April 1, 2005, the date when new
rates became effective. In Q1, 2005, NSPI deferred $15.3 million of
provincial and federal grants and taxes. The amount of the deferral
and the amortization period are pending approval by the UARB.
11. Deferred Charges and Other Receivables
Deferred Charges
NSPI has a $147 million regulatory asset related to pre-2003 income
taxes that have been paid, but not yet recovered from customers.
This circumstance arose when NSPI claimed deductions that were
ultimately disallowed by a decision of the Supreme Court of Canada.
In its decision on NSPI's 2005 rate application, the UARB has
approved the amortization and recovery of this regulatory asset over
eight years, commencing in 2007.
Other Receivables
The Company's natural gas supply contract contains a clause whereby
the arbitration process has triggered a price adjustment clause
covering the next three years of natural gas purchases. NSPI will
pay for all gas purchases at an estimated future contract price, but
will be entitled to a price rebate on a portion of the volume to be
settled in November 2007. Management's best estimate of the price net
of rebate is included in fuel for generation and purchased power
expense, with the estimated rebate recorded in Deferred Charges and
Other Receivables.
12. Investments
Investments are comprised of the following:
September 30 December 31
(millions of dollars) 2005 2004
---------------------------------------------------------------------
Equity accounted investments
Maritimes & Northeast Pipeline $91.0 $88.0
Maine Yankee Atomic Power Company 2.4 3.1
Maine Electric Power Company Inc. 1.5 1.4
Intragas Energy 1.9 1.9
---------------------------------------------------------------------
Total equity investments 96.8 94.4
Long-term portfolio investments 2.3 2.4
---------------------------------------------------------------------
$99.1 $96.8
---------------------------------------------------------------------
---------------------------------------------------------------------
13. Long-Term Debt
Long-term debt includes a private placement in the amount of
$10.0 million (December 31, 2004 - $10.0 million), which has pledged
as security a letter of credit.
On May 17, 2005, NSPI issued $100 million medium-term notes at a
coupon rate of 4.22% maturing May 17, 2010. The proceeds were used
to refinance $100 million 8.38% medium-term notes that matured on
that date.
In February 2004, a $140 million 7.3% medium-term note matured and
was refinanced with short-term debt.
14. Common Shares and Non-Controlling Interest
As of September 30, 2005 there were 109,879,841 (December 31, 2004 -
108,865,616) issued and outstanding common shares, 395,684
(December 31, 2004 - 1,083,759) common shares reserved for issuance
under the senior management common share option plan, and 1,301,832
(December 31, 2004 - 1,403,376) common shares reserved for issuance
under the employee common share purchase plan.
During the nine months ended September 30, 2005, the Company issued
1,014,225 (2004 - 485,975) common shares for cash proceeds of
$16.9 million (2004 - $7.8 million). Additionally, $0.7 million
(2004 - $0.8 million) was recognized as share compensation. Common
shares were issued through the employee common share purchase plan,
the senior management common share option plan, and the dividend
reinvestment plan.
As of September 30, 2005 and December 31, 2004 the Company's
principal subsidiary, Nova Scotia Power Inc., had outstanding the
following First Preferred Share Units:
- 4,998,695 4.9%, par value $25, Series C, which if not redeemed, in
whole or in part, by Nova Scotia Power Inc. on or after April 1,
2009, will be exchangeable into common shares of Emera Inc.
- 5,400,000 5.9%, par value $25, Series D, which if not redeemed, in
whole or in part, by Nova Scotia Power Inc. on or after
October 15, 2015, will be exchangeable into common shares of
Emera Inc.
As of September 30, 2005 the Company's subsidiary, Bangor Hydro-
Electric Company, had outstanding the following Preferred Share
Units:
- 6,266 (December 31, 2004 - 6,276) non-callable, 7% preferred
shares.
15. Related Party Transactions
In the ordinary course of business, the Company purchased natural gas
transportation capacity totaling $9.9 million (2004 - $11.5 million)
for the three months ended September 30, 2005, and $30.0 million
(2004 - $35.3 million) for the nine months ended September 30, 2005,
from the Maritimes & Northeast Pipeline, an investment under
significant influence of the Company. The amount is recognized in
fuel for generation and purchased power or netted against energy
marketing margin in other revenue, and is measured at the exchange
amount. As at September 30, 2005 the amount payable to the related
party is $3.3 million (December 31, 2004 - $3.2 million), and is
non-interest bearing and is under normal credit terms.
16. Contingencies
Effective January 1, 2005 M&NP was permitted to collect proposed
rates from customers, pending regulatory approval of new rates. Any
cash collected in excess of the new rates, once approved, will be
returned to customers. On June 28, 2005 M&NP submitted an offer of
settlement to the Federal Energy Regulatory Commission. The Company
recognized its best estimate of $0.3 million for the three months
ended September 30, 2005, and $3.3 million for the nine months ended
September 30, 2005, in equity earnings and energy marketing margin,
which represents revenue recognized in excess of existing approved
rates, and is based on the terms of the proposed settlement.
As part of an ongoing litigation against a coal supplier, NSPI was
required to post a bond. The bond may be called if NSPI does not
prosecute the claim without delay, or if the claim is not successful.
It is not determinable whether NSPI will be successful with its
claim, accordingly, an estimate of the potential contingent loss
cannot be made.
17. Comparative Information
Certain of the comparative figures have been reclassified to conform
to the consolidated financial statement presentation adopted for
2005.
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