HALIFAX, Nov. 3 /CNW/ - (TSX - EMA): Emera Inc.'s consolidated net
earnings were $19.5 million in Q3 2006 compared to $15.9 million in Q3 2005.
Emera's earnings per share were $0.18 in Q3 2006 compared to $0.14 in Q3 2005.
"Emera continues to post solid financial results in 2006," said Chris
Huskilson, President and Chief Executive Officer of Emera Inc. "We remain
focused on two priorities. First, ensuring our regulated electric utilities
consistently recover their costs of service and earn appropriate returns. And
second, building on this solid foundation with new investments like the
Northeast Reliability Interconnect and the Brunswick Pipeline that will grow
earnings over time."
The quarterly earnings improvement reflects higher earnings at the
Company's largest subsidiary, Nova Scotia Power Inc. (NSPI). NSPI's
contribution to consolidated earnings was $12.7 million in Q3 2006, compared
with $2.7 million in Q3 2005. The re-establishment of earnings levels in 2006
is due to the combined effect of an electricity price increase earlier this
year; and higher proceeds from the resale of natural gas, which reduce overall
fuel costs. Sales and production volume decreases associated with the
temporary shutdown of a large industrial customer had a minimal effect on
electricity margin in the quarter. On October 10th, Nova Scotia Power
requested an average 7.5% increase in electricity rates for the coming year,
to recover higher projected fuel costs, and previously deferred and approved
expenses. Hearings are scheduled to begin January 22, 2007.
Bangor Hydro Electric (BHE), Emera's electricity transmission and
distribution utility in Maine, contributed $5.1 million to consolidated net
earnings in Q3 2006 compared to $4.4 million in Q3 2005. Lower operating
expenses reflecting the capitalization of costs associated with the Northeast
Reliability Interconnect transmission project more than offset the effects of
a stronger Canadian dollar.
Emera's Other operations contributed $1.7 million to Q3 2006 consolidated
net earnings compared to $8.8 million in Q3 2005. Increased interest expense
in Other due primarily to foreign exchange gains in Q3 2005 and lower energy
marketing margins were key factors.
Consolidated cash provided by operating activities was $98.8 in Q3 2006,
compared to $116.7 million in Q3 2005 reflecting increased net operating
working capital requirements.
Teleconference Call
Emera is holding a teleconference today at 4:00 pm Atlantic (3:00 pm
Toronto/Montreal/New York; 2:00 pm Winnipeg; noon Vancouver) to discuss the
Q3, 2006 financial results. Analysts and other interested parties wanting to
participate in the call should dial 1-888-575-8232 (in Toronto 416-406-6419)
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 3201405(Pound key) (available until
midnight, Friday, November 17, 2006). 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).
About Emera Inc.
Emera Inc. (EMA-TSX) is an energy and services company with $4.0 billion
in assets. Electricity is Emera's core business. The company has two wholly-
owned regulated electric utility subsidiaries, Nova Scotia Power Inc. and
Bangor Hydro-Electric Company, which together serve 590,000 customers. Emera's
other investments include a joint venture interest in Bear Swamp, a 600
megawatt pumped storage hydro-electric facility in northern Massachusetts; 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.
Management's Discussion & Analysis
As at November 3, 2006
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 2006 relative to 2005, year to date
2006 relative to 2005, and its financial position at September 30, 2006
relative to December 31, 2005. 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, 2006, and the Emera Inc.
MD&A and annual audited consolidated financial statements and supporting notes
as at and for the year ended December 31, 2005. 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. 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. 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 owns and operates
two regulated electric utilities in northeastern North America. Both
businesses operate as monopolies in their service territories, and together
comprise approximately 95% of consolidated revenues:
<<
- Nova Scotia Power Inc. ("NSPI") is an electricity generation,
transmission and distribution company, providing service to the vast
majority of the province of Nova Scotia. NSPI has $3 billion of assets,
and 470,000 customers. NSPI is a cost of service utility. As such,
regulated electricity rates are set to enable the company to recover
all prudently incurred costs, with an opportunity to earn a prescribed
rate of return. The company is regulated by the Nova Scotia Utility and
Review Board ("UARB").
- Bangor Hydro-Electric Company ("BHE") is an electricity transmission
and distribution company with $580 million of assets serving
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"). BHE is a cost of service utility, with an
alternate rate plan ("ARP") for its distribution operations.
The success of Emera's electric utilities is integral to the creation of
shareholder value, providing substantial earnings and cash flow to fund
dividends and reinvestment. The essential nature of the services provided, the
monopoly positions, and the regulated market structures means that NSPI and
BHE can generally be expected to produce relatively stable earnings streams,
within regulated ranges. Nova Scotia and Maine are mature electricity markets,
with annual demand growth of approximately 2%. Accordingly, Emera must look
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 primarily focused on building on its core
electricity business, specifically in regulated transmission and distribution
operations, and low risk generation facilities.
Investment in Brunswick Pipeline
In May 2006, Emera announced that it plans to invest approximately
$350 million for full ownership of a proposed pipeline, which will deliver
natural gas from the planned Canaport(TM) Liquefied Natural Gas ("LNG") import
terminal near Saint John, New Brunswick to markets in Canada and the US
Northeast. The 145 kilometer Brunswick Pipeline would travel through southwest
New Brunswick and connect with the US portion of the Maritimes & Northeast
Pipeline ("M&NP") at the Canada/US border near Baileyville, Maine. Emera has
been an investor in M&NP since its inception in 1999.
Canaport(TM) LNG is a partnership of Repsol YPF, S.A. ("Repsol") and
Irving Oil Limited. Emera has negotiated a 25 year send or pay toll agreement
with Repsol to transport natural gas through the Brunswick Pipeline. Emera has
also negotiated agreements with its M&NP partner, Duke Energy, which will see
an affiliate of Duke Energy continue its lead role in the Brunswick pipeline
permitting process, and construct and operate the pipeline on Emera's behalf.
Emera expects to finance the investment with a combination of equity and
debt. The investment is forecast to provide a return on equity of 11% - 14%.
The project requires National Energy Board approval. A formal filing has
been made, and a public hearing is scheduled to begin November 6, 2006. The
pipeline is expected to be in service by the end of 2008.
Emera's net cash requirements related to Brunswick Pipeline are expected
to be minimal for the remainder of the year.
Standard & Poor's Debt Rating Downgrade
In Q2 2006, Standard & Poor's ("S&P") rating agency lowered the corporate
credit ratings of Emera and Nova Scotia Power to BBB/Stable Outlook from
BBB+/Negative Outlook. S&P cited concerns related to the recovery of fuel-
related expenses under the current regulatory framework in Nova Scotia; an
evolving fuel procurement strategy; and upcoming challenges related to the
approval, financing, and execution of several proposed capital projects as
reasons for the change.
The downgrade could have cost implications for Emera and Nova Scotia Power
as the companies re-finance existing debt in future years, issue new capital
or enter into new fuel procurement arrangements.
The ratings issued by Dominion Bond Rating Service and Moody's Investor
Services are unchanged.
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, Bear
Swamp, Brunswick Pipeline, 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 policy, 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
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Nova Scotia Power $12.7 $2.7 $74.4 $57.2
Bangor Hydro-Electric 5.1 4.4 11.5 10.9
Other 1.7 8.8 6.4 15.4
-------------------------------------------------------------------------
Consolidated net earnings $19.5 $15.9 $92.3 $83.5
-------------------------------------------------------------------------
Earnings per common share -
basic $0.18 $0.14 $0.84 $0.76
-------------------------------------------------------------------------
Earnings per common share -
diluted $0.18 $0.14 $0.82 $0.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of Q3 2006
Emera Inc.'s consolidated net earnings increased $3.6 million to
$19.5 million in Q3 2006 compared to $15.9 million for the same period in
2005. Year to date Emera's consolidated net earnings increased $8.8 million to
$92.3 million in 2006 compared to $83.5 million in 2005. Key factors in the
earnings comparison are:
- Electricity price increases in NSPI, effective April 1, 2005 and
March 10, 2006;
- The temporary shutdown of one of NSPI's large industrial customers;
- Year to date increased natural gas sales margin in NSPI;
- The deferral in Q1 2005 of $15.3 million in provincial grants and taxes
and income taxes in NSPI, while the company was awaiting regulatory
approval of new rates; and
- Foreign exchange gains in Other in 2005 that have not recurred in 2006.
The financial impact of these factors is summarized in the following
table:
Three months Nine months
ended ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
Consolidated net earnings - 2005 $15.9 $83.5
Increased electric revenue in NSPI due to
electricity price increases and increased
export sales 19.9 71.8
Decreased electric revenue in NSPI due to
reduced industrial sales volume and warmer
weather year to date (21.5) (73.9)
Decreased fuel expense in NSPI due to reduced
load and increased natural gas sales margin 23.3 110.3
Decreased (increased) fuel expense in NSPI due
to lower (higher) commodity prices and
increased export sales 1.0 (22.5)
Increased operating, maintenance and general
costs in NSPI mainly due to pension costs (5.9) (10.8)
Increased depreciation in NSPI primarily due
to an increase in UARB approved depreciation
rates (2.0) (6.4)
Increased taxes in NSPI primarily due to higher
taxable income (6.7) (32.8)
Deferral of Q1 2005 taxes in NSPI - (15.3)
Increased interest expense in Other due
primarily to foreign exchange gains in Q3 2005
on US denominated financial obligations; year
over year includes a favourable adjustment in
Q2 2005 to refine prior years' foreign
exchange estimates (5.9) (8.5)
All other 1.4 (3.1)
-------------------------------------------------------------------------
Consolidated net earnings - 2006 $19.5 $92.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q3 basic earnings per share were $0.18 in 2006, compared to $0.14 in 2005;
and $0.84 year to date in 2006, compared to $0.76 for the first nine months of
2005.
NOVA SCOTIA POWER INC.
Overview
2007 Rate Application
On October 10, 2006, Nova Scotia Power filed a general rate application
reflecting a request for an average 7.5% increase in electricity prices for
2007. Continuing volatile fuel prices, especially the high price of oil, is
the key driver of the application. NSPI's fuel expense is projected to be
approximately $499 million in 2007 compared to approximately $430 million
currently provided for in 2006 rates.
The rate application also includes recovery of previously deferred and
paid taxes approved by the UARB but not yet incorporated into rates, year
three of the phase-in of depreciation rates, and an increase of $3.4 million
in pension expense. NSPI is not requesting any change to its capital structure
or its allowed rate of return on equity, which is currently set in a range of
9.3% to 9.8%.
NSPI has applied for rates effective April 1, 2007. Hearings are scheduled
to begin January 22, 2007.
Extra Large Industrial Interruptible Rate ("ELIIR") Replacement
In the 2006 Rate Decision, the Nova Scotia Utility and Review Board
directed NSPI to develop and file a new rate for the customers formerly served
under the ELIIR rate. On September 28, 2006, the UARB issued its Decision,
providing these customers the choice of two different replacement rates. The
changes to the ELIIR rate should not affect the revenue requirement of NSPI,
or the ability of NSPI to recover its revenue from customers.
Leadership and Governance
Ralph Tedesco was named President and Chief Executive Officer of Nova
Scotia Power effective May 15, 2006. Mr. Tedesco was formerly NSPI's Chief
Operating Officer. He takes over from Chris Huskilson who continues in his
role as President and CEO of Emera Inc.
NSPI is also reconfiguring its Board of Directors ("Board"). John McLennan
has been named Chairman, replacing Derek Oland who continues as Chairman of
Emera. Several Emera Directors, including Mr. Huskilson, will continue to
serve on the reconfigured NSPI Board, with a new Director to be added in the
coming months.
2006 Rate Decision
The Nova Scotia Utility and Review Board granted NSPI an average rate
increase of approximately 8.7% effective March 10, 2006. The rate decision is
expected to increase NSPI's total electric revenues by approximately
$90 million. NSPI's allowed return on equity ("ROE") was maintained between
9.3% and 9.8%.
The UARB noted improvements NSPI had made in fuel procurement, but
determined that a previous finding related to 2002 and 2003 fuel procurement
carried over into 2006, resulting in a $15.7 million disallowance for 2006.
The UARB noted that this would be the final disallowance related to this
issue.
Review of Q3 2006
NSPI Q3 Net Earnings
millions of dollars (except Three months ended Nine months ended
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Electric revenue $219.9 $221.5 $710.0 $712.1
-------------------------------------------------------------------------
Fuel for generation and
purchased power 68.0 97.9 205.1 294.4
Operating, maintenance and
general 53.5 47.6 151.0 140.2
Provincial grants and taxes 10.1 10.1 30.2 30.2
Provincial grants and taxes
deferral - - - (4.9)
Depreciation 32.0 30.0 95.7 89.3
Regulatory amortization 1.6 1.6 4.7 4.7
Other (3.1) (3.0) (8.3) (7.5)
-------------------------------------------------------------------------
Earnings before interest and
income taxes 57.8 37.3 231.6 165.7
Interest 27.0 23.1 78.0 72.1
Amortization of defeasance costs 3.2 3.3 9.5 9.9
-------------------------------------------------------------------------
Earnings before income taxes 27.6 10.9 144.1 83.7
Income taxes 11.6 4.9 59.8 27.0
Income taxes deferral - - - (10.4)
-------------------------------------------------------------------------
Net earnings before preferred
dividends 16.0 6.0 84.3 67.1
Preferred dividends 3.3 3.3 9.9 9.9
-------------------------------------------------------------------------
Contribution to consolidated net
earnings $12.7 $2.7 $74.4 $57.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share $0.11 $0.02 $0.67 $0.52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's net earnings increased $10.0 million to $12.7 million in Q3 2006,
compared to $2.7 million in Q3 2005. Year to date net earnings increased
$17.2 million to $74.4 million compared to $57.2 million in 2005.
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 -
2005 $2.7 $57.2
Increased electric revenue due to electricity
price increases and increased export sales 19.9 71.8
Decreased electric revenue due to reduced
industrial sales volume and warmer weather
year to date (21.5) (73.9)
Decreased fuel expense due to reduced load and
increased natural gas sales margin 23.3 110.3
Decreased (increased) fuel expense due to lower
(higher) commodity prices and increased export
sales 1.0 (22.5)
Increased operating, maintenance and general
costs mainly due to pension costs (5.9) (10.8)
Increased depreciation primarily due to an
increase in UARB approved depreciation rates (2.0) (6.4)
Increased interest expense due to higher long-
term debt balances and foreign exchange
losses on USD contracts (3.9) (5.9)
Increased taxes primarily due to higher taxable
income (6.7) (32.8)
Deferral of Q1 2005 taxes - (15.3)
All other 5.8 2.7
-------------------------------------------------------------------------
Contribution to consolidated net earnings -
2006 $12.7 $74.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q3 Electric Sales Volume Q3 Electric Sales Revenues
Gigawatt hours ("GWh") millions of dollars
----------------------------------- ------------------------------------
2006 2005 2004 2006 2005 2004
----------------------------------- ------------------------------------
Residential 763 783 802 Residential $90.1 $85.1 $83.3
Commercial 743 731 729 Commercial 70.0 63.8 61.8
Industrial 675 1,076 1,064 Industrial 44.8 61.2 56.3
Other 180 104 106 Other 15.0 11.4 9.7
----------------------------------- ------------------------------------
Total 2,361 2,694 2,701 Total $219.9 $221.5 $211.1
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
YTD Electric Sales Volume YTD Electric Sales Revenues
Gigawatt hours ("GWh") millions of dollars
----------------------------------- ------------------------------------
2006 2005 2004 2006 2005 2004
----------------------------------- ------------------------------------
Residential 2,911 3,001 2,986 Residential $324.4 $307.2 $299.5
Commercial 2,281 2,276 2,211 Commercial 213.2 198.3 192.0
Industrial 1,949 3,176 3,129 Industrial 126.3 176.6 167.3
Other 565 292 320 Other 46.1 30.0 30.3
----------------------------------- ------------------------------------
Total 7,706 8,745 8,646 Total $710.0 $712.1 $689.1
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Q3 Average Revenue /
Megawatt hour ("MWh")
-----------------------------------
2006 2005 2004
-----------------------------------
Dollars per
MWh $93 $82 $78
-----------------------------------
-----------------------------------
YTD Average Revenue /
Megawatt hour ("MWh")
-----------------------------------
2006 2005 2004
-----------------------------------
Dollars per
MWh $92 $81 $80
-----------------------------------
-----------------------------------
Electric revenues decreased $1.6 million to $219.9 million in Q3 2006
compared to $221.5 million in Q3 2005 due to the temporary shutdown of a large
industrial customer primarily offset by the 8.7% rate increase effective March
10, 2006 and export sales.
Year to date electric revenues decreased $2.1 million to $710.0 million in
2006, compared to $712.1 million in 2005 for the reasons noted above and
warmer weather year to date. Also offsetting the year-to-date revenue decrease
is the 5.3% rate increase effective April 1, 2005.
The increase in average revenue per MWh in the quarter and year to date
reflects the rate increases noted above, and a change in sales mix,
specifically a reduction in industrial sales.
Fuel for Generation and Purchased Power
Q3 Production Volume
GWh
-------------------------------------------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
Coal and petcoke 2,121 2,153 2,290
Natural gas 122 67 24
Oil - 336 286
Renewable 205 146 99
Purchased power 78 120 122
-------------------------------------------------------------------------
Total 2,526 2,822 2,821
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Purchased power includes 20 GWh of wind power in 2006 (2005 - 15 GWh).
YTD Production Volume
GWh
-------------------------------------------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
Coal and petcoke 6,760 6,835 7,019
Natural gas 262 162 71
Oil 257 1,139 1,265
Renewable 765 755 624
Purchased power 225 404 300
-------------------------------------------------------------------------
Total 8,269 9,295 9,279
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Purchased power includes 76 GWh of wind power in 2006 (2005 - 54 GWh).
Q3 Average Unit Fuel Costs
-------------------------------------------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
Dollars per MWh $27 $35 $25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
YTD Average Unit Fuel Costs
-------------------------------------------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
Dollars per MWh $25 $32 $23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three months ended September 30, 2006, fuel for generation and
purchased power decreased $29.9 million to $68.0 million, compared to
$97.9 million in Q3 2005. Year to date fuel for generation and purchased power
decreased $89.3 million to $205.1 million, compared to $294.4 million in 2005.
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 - 2005 $97.9 $294.4
Decreased load due to the temporary shutdown
of a large industrial customer and warmer
weather year to date (20.6) (74.5)
Increased net proceeds from the resale of
natural gas (2.7) (35.8)
Commodity pricing (decrease) increase (3.4) 13.1
Increased export sales 2.4 9.4
Increased hydro production (4.4) (1.5)
All other (1.2) -
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2006 $68.0 $205.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating, Maintenance & General Expenses
NSPI's operating, maintenance and general expenses ("OM&G") were
$53.5 million in Q3 2006 compared to $47.6 million in Q3 2005, and year to
date OM&G expenditures were $151.0 million compared to $140.2 million for the
same period in 2005. These increases primarily reflect higher pension costs.
Provincial Grants and Taxes
In Q1 2005, the UARB agreed to allow NSPI to defer taxes not included in
rates for the period from January 1, 2005 until April 1, 2005, the date when
new rates became effective. As a result, NSPI deferred a portion of provincial
grants and taxes relating to Q1 2005. NSPI has proposed in its 2007 Rate
Application to amortize the deferred amount over an eight year period,
beginning when new rates become effective.
Interest
Interest expense increased $3.9 million, to $27.0 million in Q3 2006,
compared to $23.1 million in Q3 2005, and increased $5.9 million, to
$78.0 million year to date, compared to $72.1 million for the same period in
2005. These increases are due to the issuance in November 2005 of a
$150 million 5.67% medium-term note which partially refinanced short-term
debt, and foreign exchange losses.
Income Taxes
In addition to the deferral of provincial grants and taxes referred to
above, in Q1 2005, NSPI deferred a portion of federal capital taxes and income
taxes reflecting increases in these taxes since rates were last set in 2002.
NSPI has proposed in its 2007 Rate Application to amortize the deferred amount
over an eight year period, beginning when new rates become effective.
Outlook
The company's largest industrial customer has been shut down since
December 2005 and is currently in the process of restarting operations. Nova
Scotia Power's financial outlook incorporates the effect of this circumstance,
the 2006 Rate Case Decision, the ELIIR decision, and actual results to date.
The company expects to earn a regulated return on equity within its allowed
range in 2006.
BANGOR HYDRO-ELECTRIC COMPANY
BHE's core business is 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 2006
Bangor Hydro Q3 Net Earnings
millions of dollars (except Three months ended Nine months ended
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
T&D electric revenues $26.5 $26.3 $76.3 $79.6
Resale of purchased power 3.6 3.4 11.5 9.6
-------------------------------------------------------------------------
Total electric revenue 30.1 29.7 87.8 89.2
Purchased power and fuel for
generation 6.7 7.3 23.2 23.9
Operating, maintenance and
general 6.3 7.2 20.1 23.5
Property taxes 1.3 1.4 4.0 4.1
Depreciation 3.2 3.0 9.7 9.2
Regulatory amortization 4.4 3.5 10.6 9.7
Other (1.4) (1.1) (3.8) (3.1)
-------------------------------------------------------------------------
Earnings before interest and
income taxes 9.6 8.4 24.0 21.9
Interest 2.4 2.4 7.6 7.4
-------------------------------------------------------------------------
Earnings before income taxes 7.2 6.0 16.4 14.5
Income taxes 2.6 2.4 6.2 5.6
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - USD $4.6 $3.6 $10.2 $8.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - CAD $5.1 $4.4 $11.5 $10.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share - CAD $0.05 $0.04 $0.11 $0.10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted average
foreign exchange rate - CAD/USD $1.11 $1.22 $1.13 $1.22
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was $4.6 million
in Q3 2006, compared to $3.6 million in Q3 2005. Year to date, Bangor Hydro's
contribution to consolidated net earnings was $10.2 million, compared to
$8.9 million in 2005. 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 -
2005 $3.6 $8.9
Increased overheads being capitalized
primarily as a result of capital expenditures
on the Northeast Reliability Interconnect
transmission project 1.1 2.6
Decreased energy sales largely due to warmer
weather year to date (0.1) (1.4)
All other - 0.1
-------------------------------------------------------------------------
Contribution to consolidated net earnings -
2006 $4.6 $10.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was $5.1 million
CAD in Q3 2006 compared to $4.4 million CAD in Q3 2005. Year to date Bangor
Hydro's contribution to consolidated net earnings was $11.5 million CAD,
compared to $10.9 million CAD in 2005.
T&D Electric Revenue
Q3 T&D Sales Volume Q3 T&D Sales Revenues
GWh millions of dollars
----------------------------------- ------------------------------------
2006 2005 2004 2006 2005 2004
----------------------------------- ------------------------------------
Residential 144 146 138 Residential $12.1 $12.2 $13.3
Commercial 164 167 157 Commercial 9.8 9.2 10.9
Industrial 91 109 110 Industrial 2.6 3.6 3.7
Other 3 3 3 Other 2.0 1.3 1.0
----------------------------------- ------------------------------------
Total 402 425 408 Total $26.5 $26.3 $28.9
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
YTD T&D Sales Volume YTD T&D Sales Revenues
GWh millions of dollars
----------------------------------- ------------------------------------
2006 2005 2004 2006 2005 2004
----------------------------------- ------------------------------------
Residential 434 446 438 Residential $36.2 $38.1 $41.4
Commercial 457 463 453 Commercial 27.3 28.0 31.7
Industrial 279 304 257 Industrial 8.5 9.6 10.6
Other 9 9 9 Other 4.3 3.9 3.0
----------------------------------- ------------------------------------
Total 1,179 1,222 1,157 Total $76.3 $79.6 $86.7
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Q3 Average Revenue / MWh
-----------------------------------
2006 2005 2004
-----------------------------------
Dollars per
MWh $66 $62 $71
-----------------------------------
-----------------------------------
YTD Average Revenue / MWh
-----------------------------------
2006 2005 2004
-----------------------------------
Dollars per
MWh $65 $65 $75
-----------------------------------
-----------------------------------
T&D electric revenues increased by $0.2 million in Q3 2006, to
$26.5 million compared to $26.3 million in Q3 2005.
Year to date, Bangor Hydro's T&D electric revenues decreased $3.3 million
to $76.3 million compared to $79.6 million for the same period largely due to
the stranded cost rate reduction on March 1, 2005 and decreased energy sales
due to warmer weather year to date.
Rate Changes
On February 25, 2005, the MPUC approved BHE's stranded cost rates for the
three-year period March 1, 2005 to February 29, 2008. The stranded cost rates
were reduced to reflect 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, the impact on
net earnings is expected to be minimal.
Effective July 1, 2006 BHE reduced its distribution rates by 1.8%. The
decrease is the fourth decrease under a five-year Alternative Rate Plan, which
provides for an earnings band of 5% to 17% return on distribution operations,
with rates set at the midpoint of 11%.
The decrease in distribution rates offsets most of the increase in
transmission rates, which are adjusted each July 1 for the previous year's
activity.
Operating, Maintenance and General Expenses
Operating expenses were $6.3 million in Q3 2006, compared to $7.2 million
in Q3 2005 primarily due to increased overheads being capitalized primarily as
a result of capital expenditures on the Northeast Reliability Interconnect
transmission project.
Year to date operating expenses were $20.1 million, compared to
$23.5 million for the reason noted above.
Outlook
BHE net earnings for 2006 are expected to be marginally higher than 2005.
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 Maritime &
Northeast Pipeline 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.
- 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.
Investment in Brunswick Pipeline
In May 2006, Emera announced that it plans to invest approximately
$350 million for full ownership of a proposed pipeline, which will deliver
natural gas from the planned Canaport(TM) Liquefied Natural Gas import
terminal near Saint John, New Brunswick to markets in Canada and the US
Northeast. The 145 kilometer Brunswick Pipeline would travel through southwest
New Brunswick and connect with the US portion of Maritimes & Northeast
Pipeline at the Canada/US border near Baileyville, Maine. Emera has been an
investor in M&NP since its inception in 1999.
Canaport(TM) LNG is a partnership of Repsol YPF, S.A. and Irving Oil
Limited. Emera has negotiated a 25 year send or pay toll agreement with Repsol
to transport natural gas through the Brunswick Pipeline. Emera has also
negotiated agreements with its M&NP partner, Duke Energy, which will see an
affiliate of Duke Energy continue its lead role in the Brunswick pipeline
permitting process, and construct and operate the pipeline on Emera's behalf.
Emera expects to finance the investment with a combination of equity and
debt. The investment is forecast to provide a return on equity of 11% - 14%.
The project requires National Energy Board approval. A formal filing has
been made, and a public hearing is scheduled to begin November 6, 2006. The
pipeline is expected to be in service by the end of 2008.
Emera's net cash requirements related to Brunswick Pipeline are expected
to be minimal for the remainder of the year.
Review of Q3 2006
Other Q3 Net Earnings
millions of dollars (except Three months ended Nine months ended
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Electric revenue $7.4 $10.8 $20.9 $17.3
Energy marketing margin 6.5 8.1 15.1 19.2
Equity earnings 1.2 1.5 3.7 4.8
-------------------------------------------------------------------------
Total revenue 15.1 20.4 39.7 41.3
Purchased power 5.7 7.2 14.0 11.8
Operating, maintenance and
general 4.6 6.3 14.5 16.3
Business development 1.0 0.6 2.2 1.1
Depreciation 0.6 0.5 1.7 1.3
Other (1.0) (2.0) (3.1) (4.1)
-------------------------------------------------------------------------
Earnings before interest and
income taxes 4.2 7.8 10.4 14.9
Interest 2.5 (3.4) 6.4 (2.1)
-------------------------------------------------------------------------
Earnings before income taxes 1.7 11.2 4.0 17.0
Income taxes - 0.2 (2.4) 0.7
-------------------------------------------------------------------------
Net earnings from continuing
operations 1.7 11.0 6.4 16.3
Loss from discontinued
operations, net of tax - (2.2) - (0.9)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings $1.7 $8.8 $6.4 $15.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share $0.02 $0.08 $0.06 $0.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The contribution of Other operations to consolidated net earnings
decreased $7.1 million quarter over quarter and $9.0 million year to date 2006
compared to 2005. 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 -
2005 $8.8 $15.4
Increased interest expense due primarily to
foreign exchange gains in Q3 2005 on US
denominated financial obligations; year over
year includes a favourable adjustment in Q2
2005 to refine prior years' foreign exchange
estimates (5.9) (8.5)
Decreased energy marketing margin due to
reduced natural gas marketing opportunities (1.6) (4.1)
Reduced electric margin from the Bear Swamp
hydro-electric facility; year over year
reflects the addition of the Bear Swamp hydro-
electric facility (1.9) 1.4
Loss from discontinued operations, net of tax 2.2 0.9
All other 0.1 1.3
-------------------------------------------------------------------------
Contribution to consolidated net earnings -
2006 $1.7 $6.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue and Purchased Power
Electric revenue and purchased power represents Emera's pro-rata share of
electric revenue and purchased power from Bear Swamp, which was acquired in
May 2005.
As a pumped storage hydro-electric facility, the plant typically purchases
power during lower priced off peak periods and generates power during higher
priced on peak periods.
Energy Marketing Margin
Emera Energy Services net margin decreased quarter over quarter to
$6.5 million in Q3 2006, from $8.1 million in Q3 2005 and decreased year to
date to $15.1 million compared to $19.2 million in 2005 as a result of reduced
natural gas marketing opportunities.
Equity Earnings
Equity earnings from the M&NP decreased to $1.2 million in Q3 2006
compared to $1.5 million for the same period in 2005 and decreased to
$3.7 million year to date in 2006 compared to $4.8 million in 2005.
On May 16, 2006 M&NP filed an application with the FERC to expand its US
pipeline system to connect the proposed Brunswick Pipeline to markets in the
US Northeast. Construction of the proposed expansion facilities is anticipated
to begin in June 2007, in conjunction with the building of Brunswick Pipeline.
In 2004 M&NP filed a Notice of Rate Increase for its US operations.
Effective January 1, 2005 M&NP was permitted to collect proposed rates from
customers, pending approval of new rates. On June 28, 2005 M&NP submitted an
offer of settlement to the FERC, which was approved without modification on
May 15, 2006. The company had been recognizing its best estimate of rates in
equity earnings and energy marketing margin in Emera Energy Services based on
the terms of the proposed settlement. As a result, there are no adjustments to
earnings to account for the approved new rates.
Discontinued Operations
Effective September 30, 2005, Emera sold its oil distribution business.
Consolidated Balance Sheets
Significant changes in the consolidated balance sheets between
September 30, 2006 and December 31, 2005 include:
- $48.0 million decrease in accounts receivable, reflecting decreased
activity in Energy Services, partially offset by increases in NSPI
related to the 2005 and 2006 electricity price increases and lower
accounts receivable securitization.
- $15.1 million decrease in income tax receivable (now reflected as
payable) due to tax expense being higher than installment payments in
NSPI.
- $45.2 million increase in inventory, reflecting higher fuel inventory
levels and pricing in NSPI.
- $30.1 million increase in prepaid expenses, reflecting the timing of
provincial grants in lieu and insurance payments in NSPI, as well as
increased posted margin paid to counterparties in Emera Energy
Services.
- $14.2 million increase in long-term receivable, reflecting the
estimated natural gas price adjustment in NSPI.
- $39.6 million decrease in deferred charges, reflecting normal
amortization and a reduction in NSPI's deferred pension asset.
- $11.6 million decrease in total property, plant and equipment,
reflecting depreciation expense in excess of capital additions.
- $31.6 million decrease in accounts payable and accrued charges,
reflecting decreased activity in Emera Energy Services, partially
offset by a payable relating to the Brunswick Pipeline project.
Outstanding Share Data
Common Share
Capital
Millions of millions
Issued and Outstanding: Shares of dollars
-------------------------------------------------------------------------
January 1, 2005 108.87 $1,017.2
Issued for cash under purchase plans 0.43 7.9
Options exercised under senior management share
option plan 0.80 13.0
Share-based compensation - 1.1
-------------------------------------------------------------------------
December 31, 2005 110.10 1,039.2
Issued for cash under purchase plans 0.40 6.4
Options exercised under senior management share
option plan 0.30 5.7
Share-based compensation - 0.7
-------------------------------------------------------------------------
September 30, 2006 110.80 $1,052.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liquidity and Capital Resources
Emera and Nova Scotia Power have debt shelf prospectuses in the amount of
$300 and $400 million respectively that provide the companies with access to
long-term debt. Emera and Nova Scotia Power have $300 million and $150 million
respectively that remained unused as at September 30, 2006 and December 31,
2005. The prospectuses expire in April 2007.
In Q2 2006, Standard & Poor's rating agency lowered the corporate credit
ratings of Emera and Nova Scotia Power to BBB/Stable Outlook from
BBB+/Negative Outlook. S&P cited concerns related to the recovery of fuel-
related expenses under the current regulatory framework in Nova Scotia; an
evolving fuel procurement strategy; and upcoming challenges related to the
approval, financing, and execution of several proposed capital projects as
reasons for the change.
The downgrade could have cost implications for Emera and Nova Scotia Power
as the companies re-finance existing debt in future years, issue new capital
or enter into new fuel procurement arrangements.
The ratings issued by Dominion Bond Rating Service ("DBRS") and Moody's
Investor Services ("Moody's") are unchanged.
Emera has the following credit ratings:
DBRS S&P Moody's
-------------------------------------------------------------------------
Sep 30 Dec 31 Sep 30 Dec 31 Sep 30 Dec 31
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------
Long-term
corporate BBB(high) BBB(high) BBB BBB+ N/A N/A
Senior
unsecured
debt BBB(high) BBB(high) BBB- BBB Baa2 Baa2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nova Scotia Power has the following credit ratings:
DBRS S&P Moody's
-------------------------------------------------------------------------
Sep 30 Dec 31 Sep 30 Dec 31 Sep 30 Dec 31
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------
Long-term
corporate A (low) A (low) BBB BBB+ N/A N/A
Senior
unsecured debt A (low) A (low) BBB BBB+ Baa1 Baa1
Preferred
stock Pfd-2(low)Pfd-2(low) P-3(high) P-2(low) N/A N/A
Commercial
paper R-1(low) R-1(low) A-2(Cdn) A-2(Cdn) P-2(Baa) P-2(Baa)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated Cash Flow Highlights
Three months ended Nine months ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Net cash provided by operating
activities $98.8 $116.7 $239.1 $200.6
Net cash used in investing
activities (57.4) (83.7) (120.0) (175.7)
Net cash used in financing
activities (63.3) (46.5) (136.1) (48.4)
-------------------------------------------------------------------------
Decrease in cash and cash
equivalents $(21.9) $(13.5) $(17.0) $(23.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash provided by operating activities was $98.8 million
in Q3 2006, compared to $116.7 million in Q3 2005. Year to date consolidated
net cash provided by operating activities was $239.1 million compared to
$200.6 million in 2005. Highlights of the changes are summarized in the
following table:
Three months Nine months
ended ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
Net cash provided by operating activities -
2005 $116.7 $200.6
Increased cash flow from earnings 3.8 33.6
Increased inventory primarily due to higher
fuel inventory levels and pricing in NSPI (2.1) (28.2)
Increased prepaid expenses primarily due to
higher posted margin requirements with
external counterparties in Emera Energy
Services (11.2) (19.7)
Lower trade receivables in Emera Energy
Services 51.5 121.6
Lower trade payables in Emera Energy Services
and in Nova Scotia Power reflecting the
timing of fuel payments and decreased posted
margin (80.3) (125.3)
Increased income taxes payable and timing of
installments in NSPI 16.4 51.9
All other 4.0 4.6
-------------------------------------------------------------------------
Net cash provided by operating activities -
2006 $98.8 $239.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash used in investing activities was $57.4 million in Q3
2006 compared to $83.7 million in Q3 2005. Year to date consolidated net cash
used in investing activities was $120.0 million compared to $175.7 million in
2005. Highlights of the changes are summarized in the following table:
Three months Nine months
ended ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
Net cash used in investing activities - 2005 $(83.7) $(175.7)
Decreased restricted cash related to posted
margin 39.0 17.4
Acquisition of Bear Swamp in Q2 2005 - 52.6
Capital expenditures related to the Northeast
Reliability Interconnect transmission project (16.3) (25.9)
Decreased capital programs 3.2 9.1
All other 0.4 2.5
-------------------------------------------------------------------------
Net cash used in investing activities - 2006 $(57.4) $(120.0)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash used in financing activities was $63.3 million in Q3
2006 compared to $46.5 million in Q3 2005. Year to date consolidated net cash
used in financing activities was $136.1 million compared to $48.4 million in
2005. Highlights of the changes are summarized in the following table:
Three months Nine months
ended ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
Net cash used in financing activities - 2005 $(46.5) $(48.4)
(Decreased) increased short-term debt (36.3) 25.4
Increased securitization of accounts receivable 20.0 -
Increased (decreased) issuance of common shares 2.0 (4.8)
Decreased long-term debt - (108.5)
All other (2.5) 0.2
-------------------------------------------------------------------------
Net cash used in financing activities - 2006 $(63.3) $(136.1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital Resources
In November 2005, NSPI filed a Notice of Application for the construction
of capital projects to comply with the air emission requirements contained in
the Provincial environmental regulations. These capital projects are for the
installation of air emissions abatement equipment at the Lingan generating
station. Total investment associated with this equipment was projected at
$177 million. Of this amount, $16 million was included in the 2006 NSPI
capital forecast.
NSPI's regulator, the UARB, approved $5 million for the installation of a
Low NOx Combustion Firing system on Lingan Unit 3 on April 5, 2006, which has
now been installed. Nova Scotia Power requested to discontinue its application
for the remaining $172 million for the flue gas desulphurization equipment in
response to requests from stakeholders for more study. The UARB agreed with
NSPI's request. A hearing on this matter took place on June 19, 2006.
Participants in the hearing agreed to take part in an Integrated Resource Plan
("IRP"), which will analyze a variety of factors to assess how best to
proceed. The IRP is expected to be completed in the first half of 2007.
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 as 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 on the balance sheet:
Deferred Hedging Losses Recognized on the Balance Sheet
millions of dollars
-------------------------------------------------------------------------
September 30 December 31
2006 2005
-------------------------------------------------------------------------
Inventory $3.2 $0.2
-------------------------------------------------------------------------
Deferred hedging losses $3.2 $0.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three and nine month periods ended September 30, the impact 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
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Fuel and purchased power
decrease (increase) $8.0 $(8.7) $28.6 $(16.6)
Interest expense increase (0.1) (0.5) (0.2) (1.5)
-------------------------------------------------------------------------
Hedging impact on earnings $7.9 $(9.2) $28.4 $(18.1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 has recorded the following mark-to-market transactions
included on the balance sheet and recognized in earnings.
Mark-to-Market Gains (Losses) Recognized on the Balance Sheet
millions of dollars
-------------------------------------------------------------------------
September 30 December 31
2006 2005
-------------------------------------------------------------------------
Accounts receivable $0.5 $8.5
Energy marketing assets 22.6 20.1
Deferred charges (0.1) -
Energy marketing liabilities (21.4) (15.0)
-------------------------------------------------------------------------
Mark-to-market gains $1.6 $13.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Mark-to-Market Gains (Losses)
Recognized in Earnings Three months ended Nine months ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Other revenue $3.7 $3.8 $(3.4) $5.1
Fuel and purchased power (3.3) - (8.1) -
Interest (0.7) (0.4) (0.4) (0.4)
Mark-to-market (losses) gains $(0.3) $3.4 $(11.9) $4.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $7.4 million (2005 - $5.9 million) during the
three months ended September 30, 2006, and $23.1 million (2005 -
$16.6 million) during the nine months ended September 30, 2006 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, 2006 the amount payable to
the related party is $5.3 million (December 31, 2005 - $4.5 million), and is
under normal interest and credit terms.
Changes in Accounting Policy
Conditional Asset Retirement Obligations
In December 2005, the Canadian Institute of Chartered Accountants ("CICA")
issued Emerging Issues Committee Abstract 159 Conditional Asset Retirement
Obligations ("EIC-159"). EIC-159 is to be applied retroactively, with
restatement of prior periods, to financial statements for interim and annual
reporting periods ending after March 31, 2006. EIC-159 was issued in response
to the diverse accounting practices that have developed with respect to the
timing of liability recognition when the timing and/or method of settlement
are conditional on a future event.
As a result of adopting EIC-159, the company has determined that it has
conditional asset retirement obligations related to the disposal of
polychlorinated biphenyls ("PCBs"). As at September 30, 2006, property, plant
and equipment has increased by $0.6 million (December 31, 2005 -
$0.6 million), accumulated depreciation has decreased by $1.9 million
(December 31, 2005 - $1.8 million), and asset retirement obligations have
increased by $2.5 million (December 31, 2005 - $2.4 million). There is no
impact to net earnings in 2006 and 2005.
Inventory
In August 2006, Nova Scotia Power changed its method of costing fuel
inventory from the first-in, first-out method to the weighted average cost
method to provide more appropriate information. The change in accounting
policy was approved by the UARB.
The CICA Handbook Section 1506 Accounting Changes requires that changes in
accounting policies be applied retroactively to all prior periods presented
for comparative purposes. Nova Scotia Power applied the change in accounting
policy retroactively but did not restate prior periods as the necessary
adjustments were considered immaterial. The change in accounting policy
resulted in a cumulative adjustment to the opening balance of fuel inventory
in Q3 2006 of $1.0 million. As a result, NSPI decreased inventory by
$1.0 million and increased fuel expense by $1.0 million in Q3 2006.
Summary of Quarterly Reports
For the quarter ended
millions of dollars (except earnings per common share)
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4
2006 2006 2006 2005
-------------------------------------------------------------------------
Total revenues $272.4 $275.9 $310.7 $297.1
-------------------------------------------------------------------------
Net earnings from
continuing operations $19.5 $29.2 $43.6 $37.7
-------------------------------------------------------------------------
Net earnings applicable to
common shares $19.5 $29.2 $43.6 $37.7
-------------------------------------------------------------------------
Earnings per common share
- basic:
Continuing operations $0.18 $0.26 $0.40 $0.34
Discontinued operations - - - -
-------------------------------------------------------------------------
$0.18 $0.26 $0.40 $0.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share
- diluted:
Continuing operations $0.18 $0.26 $0.38 $0.34
Discontinued operations - - - -
-------------------------------------------------------------------------
$0.18 $0.26 $0.38 $0.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the quarter ended
millions of dollars (except earnings per common share)
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4
2005 2005 2005 2004
-------------------------------------------------------------------------
Total revenues $281.1 $280.1 $309.7 $286.5
-------------------------------------------------------------------------
Net earnings from
continuing operations $18.1 $19.1 $47.2 $30.7
-------------------------------------------------------------------------
Net earnings applicable
to common shares $15.9 $19.3 $48.3 $31.4
-------------------------------------------------------------------------
Earnings per common share
- basic:
Continuing operations $0.16 $0.18 $0.43 $0.29
Discontinued operations (0.02) - 0.01 0.01
-------------------------------------------------------------------------
$0.14 $0.18 $0.44 $0.30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share
- diluted:
Continuing operations $0.16 $0.18 $0.41 $0.27
Discontinued operations (0.02) - 0.01 0.01
-------------------------------------------------------------------------
$0.14 $0.18 $0.42 $0.28
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 Three months ended Nine months ended
millions of dollars (except
earnings per common share) September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue
Electric $261.1 $268.0 $830.4 $838.6
Other 11.3 13.1 28.6 32.3
-------------------------------------------------------------------------
272.4 281.1 859.0 870.9
-------------------------------------------------------------------------
Cost of operations
Fuel for generation and
purchased power 81.2 113.7 245.4 335.3
Operating, maintenance, and
general 66.2 63.1 190.6 186.3
Provincial, state, and
municipal taxes 12.2 12.2 36.3 36.6
Provincial tax deferral
(note 10) - - - (4.9)
Depreciation 36.1 34.1 108.3 101.9
Regulatory amortization 6.4 5.7 16.6 16.5
Allowance for funds used
during construction (1.4) (1.4) (3.7) (3.4)
-------------------------------------------------------------------------
200.7 227.4 593.5 668.3
-------------------------------------------------------------------------
Earnings from operations 71.7 53.7 265.5 202.6
Equity earnings (note 8) 1.2 1.5 3.7 4.8
-------------------------------------------------------------------------
Earnings before interest and
income taxes 72.9 55.2 269.2 207.4
Interest (note 9) 32.2 22.6 92.9 79.0
Amortization of defeasance costs 3.2 3.3 9.5 9.9
-------------------------------------------------------------------------
Earnings before income taxes 37.5 29.3 166.8 118.5
Income taxes 14.7 7.9 64.5 34.5
Income taxes deferral (note 10) - - - (10.4)
-------------------------------------------------------------------------
Net earnings before
non-controlling interest 22.8 21.4 102.3 94.4
Non-controlling interest 3.3 3.3 10.0 10.0
-------------------------------------------------------------------------
Net earnings from continuing
operations 19.5 18.1 92.3 84.4
Loss from discontinued
operations, net of tax (note 5) - (2.2) - (0.9)
-------------------------------------------------------------------------
Net earnings applicable to
common shares $19.5 $15.9 $92.3 $83.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share -
basic
Continuing operations $0.18 $0.16 $0.84 $0.77
Discontinued operations - (0.02) - (0.01)
-------------------------------------------------------------------------
$0.18 $0.14 $0.84 $0.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share -
diluted
Continuing operations $0.18 $0.16 $0.82 $0.77
Discontinued operations - (0.02) - (0.01)
-------------------------------------------------------------------------
$0.18 $0.14 $0.82 $0.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Weighted average number of common
shares outstanding (millions)
- basic 110.6 109.7 110.4 109.4
- diluted 110.6 109.7 116.8 109.4
Consolidated Statements of Retained Earnings (Unaudited)
-------------------------------------------------------------------------
For the nine months ended September 30
millions of dollars 2006 2005
-------------------------------------------------------------------------
Retained earnings, beginning of year $423.4 $399.6
Net earnings applicable to common shares 92.3 83.5
-------------------------------------------------------------------------
515.7 483.1
Dividends 73.6 72.9
-------------------------------------------------------------------------
Retained earnings, end of period $442.1 $410.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Consolidated Balance Sheets (Unaudited)
-------------------------------------------------------------------------
As at September 30 December 31
2006 2005
Restated
millions of dollars (note 3)
-------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $4.5 $21.5
Restricted cash 14.3 5.8
Accounts receivable 183.8 231.8
Income tax receivable - 15.1
Inventory (note 3) 121.3 76.1
Prepaid expenses 46.0 15.9
Future income tax assets 14.9 9.3
Energy marketing assets 19.4 16.0
-------------------------------------------------------------------------
404.2 391.5
-------------------------------------------------------------------------
Long-term receivables 62.6 48.4
-------------------------------------------------------------------------
Energy marketing assets 3.2 4.1
-------------------------------------------------------------------------
Deferred charges 468.7 508.3
-------------------------------------------------------------------------
Future income tax assets 10.9 19.0
-------------------------------------------------------------------------
Goodwill 93.0 97.1
-------------------------------------------------------------------------
Investments (note 11) 99.3 101.0
-------------------------------------------------------------------------
Property, plant and equipment 2,732.1 2,789.2
Construction work in progress 85.5 40.0
-------------------------------------------------------------------------
2,817.6 2,829.2
-------------------------------------------------------------------------
$3,959.5 $3,998.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Current portion of long-term debt $3.6 $152.9
Short-term debt 184.3 88.1
Accounts payable and accrued charges 217.0 248.6
Income tax payable 20.4 1.5
Dividends payable 3.2 3.2
Energy marketing liabilities 17.7 12.1
-------------------------------------------------------------------------
446.2 506.4
-------------------------------------------------------------------------
Energy marketing liabilities 3.7 2.9
-------------------------------------------------------------------------
Future income tax liabilities 78.9 78.9
-------------------------------------------------------------------------
Asset retirement obligations (note 3 and note 12) 77.1 74.1
-------------------------------------------------------------------------
Deferred credits 66.5 77.5
-------------------------------------------------------------------------
Long-term debt (note 13) 1,646.7 1,631.8
-------------------------------------------------------------------------
Non-controlling interest 260.8 260.8
-------------------------------------------------------------------------
Shareholders' equity
Common shares (note 14) 1,052.0 1,039.2
Contributed surplus (note 15) 2.0 1.8
Foreign exchange translation adjustment (116.5) (98.2)
Retained earnings 442.1 423.4
-------------------------------------------------------------------------
1,379.6 1,366.2
-------------------------------------------------------------------------
$3,959.5 $3,998.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contingencies (Note 17)
See accompanying notes to the unaudited consolidated financial
statements.
Approved on behalf of the Board of Directors
"Derek Oland" "Christopher Huskilson"
Derek Oland Christopher Huskilson
Chairman President and Chief Executive Officer
Consolidated Statements of Cash Flow (Unaudited)
-------------------------------------------------------------------------
For the Three months ended Nine months ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating activities
Net earnings before
non-controlling interest $22.8 $21.4 $102.3 $94.4
Non-cash items:
Depreciation 36.1 34.1 108.3 101.9
Deferral of provincial
taxes and income taxes - - - (15.3)
Amortization of deferred
charges 3.6 3.8 10.4 11.8
Equity earnings (1.2) (1.5) (3.7) (4.8)
Regulatory amortization 6.4 5.7 16.6 16.5
Allowance for funds used
during construction (1.4) (1.4) (3.7) (3.4)
Future income taxes 2.8 4.7 6.0 9.8
Other non-cash operating items 7.0 2.7 25.4 11.4
Discontinued operations - 0.3 - 2.1
Other cash operating items (11.1) (8.6) (20.5) (16.9)
-------------------------------------------------------------------------
65.0 61.2 241.1 207.5
Change in non-cash
operating working capital 33.8 55.5 (2.0) (6.9)
-------------------------------------------------------------------------
Net cash provided by
operating activities 98.8 116.7 239.1 200.6
-------------------------------------------------------------------------
Investing activities
Property, plant and equipment (52.9) (39.3) (109.7) (92.9)
Proceeds on
disposition (note 5) - 0.1 - 0.1
Acquisition (note 4) - - - (52.6)
Retirement spending
net of salvage (0.6) (1.2) (2.2) (2.9)
Increase in restricted cash (4.3) (43.3) (8.5) (25.9)
Other investing activities 0.4 - 0.4 (1.5)
-------------------------------------------------------------------------
Net cash used in
investing activities (57.4) (83.7) (120.0) (175.7)
-------------------------------------------------------------------------
Financing activities
Retirement of long-term debt - - (150.8) (102.3)
Issuance of long-term debt - - 40.0 100.0
(Decrease) increase
in short-term debt (41.8) (5.5) 76.5 51.1
Issuance of common shares 6.0 4.0 12.1 16.9
Dividends on common shares (24.5) (24.4) (73.6) (72.9)
Dividends paid by subsidiaries
to non-controlling interest (3.3) (3.3) (10.0) (10.0)
Accounts receivable
securitization - (20.0) (30.0) (30.0)
Other financing 0.3 2.7 (0.3) (1.2)
-------------------------------------------------------------------------
Net cash used in financing
activities (63.3) (46.5) (136.1) (48.4)
-------------------------------------------------------------------------
Decrease in cash and cash
equivalents (21.9) (13.5) (17.0) (23.5)
Cash and cash equivalents,
beginning of period 26.4 32.7 21.5 42.7
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $4.5 $19.2 $4.5 $19.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents
consists of:
Cash $3.0 $18.4 $3.0 $18.4
Cash equivalents 1.5 0.8 1.5 0.8
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $4.5 $19.2 $4.5 $19.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental disclosure
of cash paid:
Interest $17.8 $36.3 $96.4 $97.4
Income and capital taxes $7.5 $15.8 $33.8 $48.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Notes to the Interim Unaudited Consolidated Financial Statements
September 30, 2006
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,
2005.
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,
2005 with the exception of the accounting policy changes 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 vary
significantly over the year, with Q1 and Q4, the strongest periods, reflecting
colder weather and fewer daylight hours in the winter season.
3. Changes in Accounting Policy
Conditional Asset Retirement Obligations
In December 2005, the Canadian Institute of Chartered Accountants ("CICA")
issued Emerging Issues Committee Abstract 159 Conditional Asset Retirement
Obligations ("EIC-159"). EIC-159 is to be applied retroactively, with
restatement of prior periods, to financial statements for interim and annual
reporting periods ending after March 31, 2006. EIC-159 was issued in response
to the diverse accounting practices that have developed under CICA Handbook
Section 3110 Asset Retirement Obligations ("Section 3110") with respect to the
timing of liability recognition when the timing and/or method of settlement
are conditional on a future event.
As a result of adopting EIC-159, the Company has determined that it has
conditional asset retirement obligations related to the disposal of
polychlorinated biphenyls ("PCBs"). As at September 30, 2006, property, plant
and equipment has increased by $0.6 million (December 31, 2005 -
$0.6 million), accumulated depreciation has decreased by $1.9 million
(December 31, 2005 - $1.8 million), and asset retirement obligations have
increased by $2.5 million (December 31, 2005 - $2.4 million). There is no
impact to net earnings in 2006 and 2005.
Accounting for the impact of rate regulation:
Any difference between the amount of depreciation and accretion expense
approved by the regulator of Nova Scotia Power and the amount that would have
been calculated under EIC-159 is recognized as a regulatory asset in
accumulated depreciation. In the absence of this deferral, year to date net
earnings for 2006 would be $0.1 million lower.
Inventory
In August 2006, Nova Scotia Power changed its method of costing fuel
inventory from the first-in, first-out method to the weighted average cost
method to provide more appropriate information. The change in accounting
policy has been approved by the UARB.
The CICA Handbook Section 1506 Accounting Changes requires that changes in
accounting policies be applied retroactively to all prior periods presented
for comparative purposes. Nova Scotia Power applied the change in accounting
policy retroactively but did not restate prior periods as the necessary
adjustments were considered immaterial. The change in accounting policy
resulted in a cumulative adjustment to the opening balance of fuel inventory
in Q3 2006 of $1.0 million. As a result, NSPI decreased inventory by
$1.0 million and increased fuel expense by $1.0 million in Q3 2006.
4. Acquisition
On May 24, 2005 Emera and Brookfield Power Corporation, 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 $61.2 million. The facility sells energy, capacity and
ancillary products into 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, Emera's
pro-rata share of the results since acquisition have been included in the
consolidated statements of earnings.
Emera's share of the transaction is as follows:
millions of dollars
-------------------------------------------------------------------------
Net assets acquired at fair value
Inventory $0.2
Property, plant and equipment 61.8
Deferred charges 0.2
Accrued liabilities (0.1)
Deferred credits (0.9)
-------------------------------------------------------------------------
Total cash consideration $61.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
5. 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 a discontinued operation.
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
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue - $19.1 - $69.7
Earnings before income taxes - (0.9) - 0.3
Loss on disposition, net of tax - (1.6) - (1.6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 were received in Q4 2005.
6. Segment Information
Segmented financial information for the three months ended and as at
September 30, 2006:
-------------------------------------------------------------------------
Bangor
millions of dollars NSPI Hydro Other(x) Total
-------------------------------------------------------------------------
Revenues from external
customers $222.7 $34.2 $15.5 $272.4
Depreciation 32.0 3.5 0.6 36.1
Cost of operations,
including depreciation 164.8 23.3 12.6 200.7
Net inter-segment operating
revenues/(expenses) 32.9 (0.8) (32.1) -
Equity earnings - - 1.2 1.2
Interest expense 27.0 2.7 2.5 32.2
Income taxes 11.6 3.1 - 14.7
Net earnings applicable to
common shares 12.7 5.1 1.7 19.5
Assets 3,066.7 581.9 310.9 3,959.5
Goodwill - 93.0 - 93.0
Capital expenditures 28.1 21.4 3.4 52.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Other consists of items related to corporate activities and other
subsidiaries.
Segmented financial information for the three months ended and as at
September 30, 2005:
-------------------------------------------------------------------------
Bangor
millions of dollars NSPI Hydro Other(x) Total
-------------------------------------------------------------------------
Revenues from external
customers $223.9 $36.6 $20.6 $281.1
Depreciation 30.0 3.6 0.5 34.1
Cost of operations, including
depreciation 186.5 26.3 14.6 227.4
Net inter-segment 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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Other consists of items related to corporate activities and other
subsidiaries.
Segmented financial information for the nine months ended and as at
September 30, 2006:
-------------------------------------------------------------------------
Bangor
millions of dollars NSPI Hydro Other(x) Total
-------------------------------------------------------------------------
Revenues from external
customers $717.2 $101.1 $40.7 $859.0
Depreciation 95.7 10.9 1.7 108.3
Cost of operations, including
depreciation 485.6 74.0 33.9 593.5
Net inter-segment operating
revenues/(expenses) 122.0 (2.2) (119.8) -
Equity earnings - - 3.7 3.7
Interest expense 78.0 8.5 6.4 92.9
Income taxes 59.8 7.1 (2.4) 64.5
Net earnings applicable to
common shares 74.4 11.5 6.4 92.3
Assets 3,066.7 581.9 310.9 3,959.5
Goodwill - 93.0 - 93.0
Capital expenditures 58.3 43.5 7.9 109.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Other consists of items related to corporate activities and other
subsidiaries.
Segmented financial information for the nine months ended and as at
September 30, 2005:
-------------------------------------------------------------------------
Bangor
millions of dollars NSPI Hydro Other(x) Total
-------------------------------------------------------------------------
Revenues from external
customers $717.9 $111.6 $41.4 $870.9
Depreciation 89.3 11.3 1.3 101.9
Cost of operations, including
depreciation 552.2 84.7 31.4 668.3
Net inter-segment 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 shares 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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 estimated cost,
related to these plans, for the three month period ended September 30, 2006 is
$10.7 million (2005 - $7.6 million), and for the nine month period ended
September 30, 2006 is $32.2 million (2005 - $22.2 million).
8. Equity Earnings
Equity earnings of $1.2 million (2005 - $1.5 million) for the three months
ended September 30, 2006, and $3.7 million (2005 - $4.8 million) for the nine
month period ended September 30, 2006 consists of the Company's pro-rata share
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:
-------------------------------------------------------------------------
For the Three months ended Nine months ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Interest on long-term debt $25.6 $25.7 $78.8 $78.9
Interest on short-term debt 5.4 5.7 10.9 12.4
Amortization of debt financing 0.5 0.4 1.5 1.4
Foreign exchange losses (gains) 0.7 (9.2) 1.7 (13.7)
-------------------------------------------------------------------------
$32.2 $22.6 $92.9 $79.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 a portion of provincial and federal
grants and taxes. The amortization period is subject to approval by the UARB.
11. Investments
Investments are comprised of the following:
-------------------------------------------------------------------------
As at September 30 December 31
millions of dollars 2006 2005
-------------------------------------------------------------------------
Equity accounted investments
Maritimes & Northeast Pipeline ("M&NP") $91.9 $92.8
Maine Yankee Atomic Power Company 1.4 2.4
Maine Electric Power Company Inc. 1.2 1.5
Intragas Energy 1.9 1.9
-------------------------------------------------------------------------
Total equity investments 96.4 98.6
Long-term portfolio investments 2.9 2.4
-------------------------------------------------------------------------
$99.3 $101.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
12. Asset Retirement Obligations
In addition to asset retirement obligations recognized under Section 3110
and EIC-159, the Company may have asset retirement obligations associated with
some of its transmission and distribution assets. As the Company expects to
use the majority of its installed assets for an indefinite period, no removal
date can be determined and consequently a reasonable estimate of the fair
value of any related asset retirement obligation cannot be made at this time.
13. Long-Term Debt
As at September 30, 2006 long-term debt includes $55.8 million of Bangor
Hydro debt, which is secured by first mortgage indentures. As at December 31,
2005, long-term debt included $58.3 million of Bangor Hydro debt, which is
secured by first mortgage indentures, and a private placement in Emera in the
amount of $10.0 million, which was secured by a letter of credit. The private
placement matured on April 24, 2006.
Long-term debt includes $4.3 million (December 31, 2005 - $0.9 million) in
capital lease obligations.
14. Common Shares
As of September 30, 2006 there were 110.8 million (December 31, 2005 -
110.1 million) issued and outstanding common shares, 5.0 million (December 31,
2005 - 0.3 million) common shares reserved and available for issuance under
the senior management stock option plan, and 1.2 million (December 31, 2005 -
1.3 million) common shares reserved and available for issuance under the
employee common share purchase plan.
During the nine months ended September 30, 2006, the Company issued
0.7 million (2005 - 1.0 million) common shares for cash proceeds of
$12.1 million (2005 - $16.9 million). Additionally, $0.7 million (2005 -
$0.7 million) was recognized as share compensation. Common shares were issued
through the employee common share purchase plan, the senior management stock
option plan, and the dividend reinvestment plan.
15. Contributed Surplus
-------------------------------------------------------------------------
millions of dollars
-------------------------------------------------------------------------
Balance, December 31, 2005 $1.8
Stock option expense 0.6
Exercise of stock options (0.4)
-------------------------------------------------------------------------
Balance, September 30, 2006 $2.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
16. Related Party Transactions
In the ordinary course of business, Emera purchased natural gas
transportation capacity totaling $7.4 million (2005 - $5.9 million) during the
three months ended September 30, 2006, and $23.1 million (2005 -
$16.6 million) during the nine months ended September 30, 2006 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, 2006 the amount payable to
the related party is $5.3 million (December 31, 2005 - $4.5 million), and is
under normal interest and credit terms.
17. Contingencies
The Company may, from time to time, be involved in legal proceedings,
claims and litigation that arise in the ordinary course of business which the
Company believes would not reasonably be expected to have a material adverse
effect on the financial condition of the Company.
In late 2005 some of Nova Scotia Power's petroleum coke (petcoke)
suppliers were unable to supply the fuel due to hurricanes in the Gulf of
Mexico, which seriously affected their operations. As a result, NSPI incurred
additional costs for replacement fuel, and other expenses. NSPI has advised
its insurers that it intends to seek recovery of applicable costs. The
insurers have advised that coverage is available under the policy but at this
time NSPI is unable to estimate the total recovery amount.
18. Comparative Information
Certain of the comparative figures have been reclassified to conform to
the consolidated financial statement presentation adopted for 2006.
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