HALIFAX, Nov. 2 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net earnings increased to $40.9 million in the third quarter of 2007 compared to $19.5 million in Q3, 2006. The increase in the quarter was largely due to a $10.8 million income tax recovery in Nova Scotia Power Inc.(NSPI). Earnings per share were $0.37 in Q3 2007 compared to $0.18 in the same period last year. Strong results year to date are driven by solid performance from Bangor Hydro-Electric (BHE) and the Bear Swamp hydro-electric generating station.
"We continue to see progress in our business," said Chris Huskilson, President and Chief Executive Officer of Emera Inc. "The Brunswick Pipeline has cleared all regulatory hurdles and construction is about to begin. In addition, construction of the Northeast Reliability Interconnect (NRI) transmission line is complete and the line will be in-service in December as planned."
NSPI earned $14.2 million before a $10.8 million income tax recovery in the third quarter compared to $12.7 million in Q3, 2006. This tax recovery is the result of the Canada Revenue Agency's approval of the deductibility of certain capitalized expenses as requested by NSPI for the years 2000 to 2004 inclusive.
Bangor Hydro-Electric earned $9.1 million in the quarter compared to $5.1 million in Q3 last year. The increase relates to increased revenue and capitalized costs associated with the NRI development partially offset by the strong Canadian dollar.
Emera's other operations contributed $6.8 million in Q3, 2007 compared to $1.7 million in Q3, 2006. The Bear Swamp generating facility had higher energy and capacity sales as well as strengthened mark-to-market on energy positions, primarily associated with the company's long term contract with the Long Island Power Authority, in the third quarter of 2007 compared to Q3 of 2006. The Maritimes & Northeast Pipeline also reported increased earnings this quarter.
Consolidated cash from operations was $82.8 million in Q3, 2007, compared to $98.8 million in Q3 2006 reflecting increased operating working capital requirements.
Teleconference Call
Emera will be hosting a teleconference at 4:00 pm Atlantic time today (3:00 pm Toronto/Montreal/New York; 2:00 pm Winnipeg; 12:00 pm Vancouver) to discuss the Q3 2007 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 3238704(number sign) (available until midnight, Friday, November 16, 2007). 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.
(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 also owns 19% of St. Lucia Electricity Services Limited, which serves more than 50,000 customers on the Caribbean island of St. Lucia. In addition to its electric utility investments, Emera has 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. Visit Emera on the web at www.emera.com.
Management's Discussion & Analysis
As at November 2, 2007
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 2007 relative to 2006, year to date 2007 relative to 2006, and its financial position at September 30, 2007 relative to 2006. Certain factors that may affect 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. To enhance shareholders' understanding, certain multi-year historical financial and statistical information is presented.
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, 2007 and the Emera Inc. MD&A and annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2006. Emera follows Canadian Generally Accepted Accounting Principles ("GAAP"). Emera's wholly-owned subsidiary, Nova Scotia Power Inc.'s accounting policies are subject to examination and approval by the Nova Scotia Utility and Review Board. Emera's wholly-owned 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 on SEDAR at www.sedar.com.
Introduction and Strategic Overview
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
typically comprise over 80% of Emera's consolidated earnings:
- 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 over $3 billion in
assets, and 475,000 customers.
- Bangor Hydro-Electric Company ("BHE") is an electricity transmission
and distribution company with $610 million in assets serving
115,000 customers in eastern Maine. 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. 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 leverages its core strength in the electricity
business. Emera will pursue investments in both acquisitions and greenfield
development opportunities in regulated electricity transmission and
distribution and low risk generation. Emera will also capitalize on investment
opportunities in related energy infrastructure businesses appropriate to its
risk profile, where its development, commercial and operational skills are
needed.
Emera's other investments include:
- Emera Energy Services, a wholly owned subsidiary, which purchases and
sells natural gas and electricity on behalf of third parties and
provides related energy asset management services.
- Bear Swamp, a 50/50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts.
- A 12.9% interest in the $2 billion, 1,400 kilometer Maritimes &
Northeast Pipeline ("M&NP") that transports Nova Scotia's offshore
natural gas to markets in Maritime Canada and the northeastern United
States.
- Brunswick Pipeline, a 145 kilometer greenfield pipeline project under
development that 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.
- In January 2007, Emera invested $22 million USD to acquire a 19% equity
interest in St. Lucia Electricity Services Limited ("Lucelec"), a
vertically integrated electric utility serving more than
50,000 customers on the Caribbean island of St. Lucia.
Income Tax Recovery in Nova Scotia Power
NSPI prepared and filed with Canada Revenue Agency ("CRA") amended tax
returns for the years 2000 to 2004 inclusive. CRA reviewed and approved the
amended filings, which has resulted in accelerated deductibility of certain
capitalized expenses. NSPI intends to amend tax returns for 2005 and 2006
using the same methodology and will continue to use this methodology when
filing its future tax returns. As a result, NSPI has recorded an income tax
recovery of $25.4 million, of which $14.6 million has been recorded as a
reduction of deferred charges, specifically the regulatory asset related to
its pre-2003 income tax liability. The remaining $10.8 million has been
recorded as a reduction of current income tax expense. Refund interest has not
been estimated on the recovery as it is not reasonably determinable at this
time.
Implementation of New Accounting Standards in Q1 2007
The Canadian Institute of Chartered Accountants ("CICA") has introduced
new classification and measurement requirements for financial instruments,
which Emera adopted in the preparation of its Q1 2007 financial statements.
These changes affect the accounting for several elements of Emera's business
including:
- hedges the company uses to manage risk of fluctuations in commodity
prices, interest rates, and foreign exchange; and
- Nova Scotia Power's natural gas supply contracts.
In some instances, the new accounting requirements result only in a
reclassification of amounts to new balance sheet accounts. For example,
"energy marketing assets and liabilities" have been reclassified as "held for
trading derivatives". An effect of the new requirement is to record the fair
value of hedges, and Nova Scotia Power's natural gas contracts as assets and
liabilities on the company's balance sheet. The recognition of these items
beginning January 1, 2007 increased Emera's total assets by $193.6 million,
with a corresponding increase of $193.6 million on the liabilities and
shareholders' equity side of the balance sheet. The net effect of the
implementation of these changes is a $0.1 million after-tax increase in net
earnings in Q3 2007 and a $1.6 million after-tax increase in net earnings
year-to-date 2007.
More detail on the implementation of these new accounting standards is
provided later in this Management's Discussion and Analysis, and in Note 3 to
the financial statements.
Structure of MD&A
This 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
consolidated results; then presents information on the company's two primary
subsidiaries, NSPI and BHE. All other operations, including Bear Swamp, Emera
Energy Services, Brunswick Pipeline, Maritimes & Northeast Pipeline, Lucelec,
and corporate activities are grouped and discussed as "Other". Significant
changes in the consolidated balance sheets, outstanding share data, liquidity
and capital resources, financial and commodity instruments, transactions with
related parties, changes in accounting policies, dividends and selected
quarterly trend information are presented on a consolidated basis.
EMERA CONSOLIDATED
Q3 Operating Unit Contributions
millions of dollars
(except earnings Three months ended Nine months ended
per common share) September 30 September 30
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Nova Scotia Power $ 25.0 $ 12.7 $ 75.0 $ 74.4
Bangor Hydro-Electric 9.1 5.1 20.8 11.5
Other 6.8 1.7 18.9 6.4
-------------------------------------------------------------------------
Consolidated net earnings $ 40.9 $ 19.5 $ 114.7 $ 92.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic $ 0.37 $ 0.18 $ 1.03 $ 0.84
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - diluted $ 0.35 $ 0.18 $ 1.00 $ 0.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of 2007
Emera Inc.'s consolidated net earnings increased $21.4 million to
$40.9 million in Q3 2007 compared to $19.5 million for the same period in
2006. Year to date Emera's consolidated net earnings increased $22.4 million
to $114.7 million in 2007 compared to $92.3 million in 2006. Highlights of the
changes are summarized in the following table:
Three months Nine months
ended ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
Consolidated net earnings - 2006 $ 19.5 $ 92.3
-------------------------------------------------------------------------
Decreased year-to-date net earnings in
NSPI due to increased fuel expense and
a new regulatory amortization partially
offset by increased revenue 1.5 (10.2)
Income tax recovery in NSPI 10.8 10.8
Increased net earnings in Bangor Hydro due
to increased revenue and capitalized costs
associated with the Northeast Reliability
Interconnect transmission project partially
offset by increased income taxes and the
effect of the stronger Canadian dollar 4.0 9.3
Increased net earnings in Other due mainly
to Bear Swamp's increased energy and
capacity sales and mark-to-market positions
and M&NP's capitalization of prior years'
expansion costs in Q1 2007 5.1 12.5
-------------------------------------------------------------------------
Consolidated net earnings - 2007 $ 40.9 $ 114.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q3 basic earnings per share were $0.37 in 2007 compared to $0.18 in 2006;
and $1.03 year to date in 2007 compared to $0.84 for the first nine months of
2006.
NOVA SCOTIA POWER INC.
Overview
NSPI is the primary electricity supplier in Nova Scotia, providing over
95% of electricity generation, transmission and distribution in the province.
Nova Scotia Power is regulated under a cost of service model, with rates set
to recover prudently incurred costs of providing electricity service to
customers, and provide an opportunity to earn a prescribed return on equity.
The company is regulated by the Nova Scotia Utility and Review Board ("UARB").
Income Tax Recovery
NSPI prepared and filed with CRA amended tax returns for the years 2000 to
2004 inclusive. CRA reviewed and approved the amended filings, which has
resulted in accelerated deductibility of certain capitalized expenses. NSPI
intends to amend tax returns for 2005 and 2006 using the same methodology and
will continue to use this methodology when filing its future tax returns. As a
result, NSPI has recorded an income tax recovery of $25.4 million, of which
$14.6 million has been recorded as a reduction of deferred charges,
specifically the regulatory asset related to its pre-2003 income tax
liability. The remaining $10.8 million has been recorded as a reduction of
current income tax expense. Refund interest has not been estimated on the
recovery as it is not reasonably determinable at this time.
2007 Rate Decision
In February 2007 the UARB approved an average increase in electricity
rates of 3.8% effective April 1, 2007. The rate increase was part of a
settlement agreement between NSPI and key stakeholders. NSPI's return on
equity range was unchanged at 9.3% to 9.8%.
A central provision of the settlement is an agreement in principle that
the UARB should establish a fuel adjustment mechanism ("FAM") for Nova Scotia
Power to ensure actual fuel costs are recovered from customers. FAM hearings,
which were scheduled to begin June 18, 2007, are now scheduled for November 5,
2007.
Review of 2007
NSPI Q3 Net Earnings
millions of dollars
(except earnings Three months ended Nine months ended
per common share) September 30 September 30
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Electric revenue $ 249.2 $ 219.9 $ 818.9 $ 710.0
-------------------------------------------------------------------------
Fuel for generation and
purchased power 94.5 68.0 323.4 205.1
Operating, maintenance
and general 50.1 53.5 150.7 151.0
Provincial grants and
taxes 10.2 10.1 30.3 30.2
Depreciation 32.8 32.0 98.0 95.7
Regulatory amortization 5.6 1.6 12.7 4.7
Other (3.6) (3.1) (8.9) (8.3)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 59.6 57.8 212.7 231.6
Interest 28.3 27.0 79.1 78.0
Amortization of
defeasance costs 3.2 3.2 9.5 9.5
-------------------------------------------------------------------------
Earnings before income
taxes 28.1 27.6 124.1 144.1
Income taxes (0.2) 11.6 39.2 59.8
-------------------------------------------------------------------------
Net earnings before
preferred dividends 28.3 16.0 84.9 84.3
Preferred dividends 3.3 3.3 9.9 9.9
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings $ 25.0 $ 12.7 $ 75.0 $ 74.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share $ 0.22 $ 0.11 $ 0.67 $ 0.67
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's contribution to consolidated net earnings increased $12.3 million
to $25.0 million in Q3 2007 compared to $12.7 million in Q3 2006. Year to date
NSPI's contribution to consolidated net earnings increased $0.6 million to
$75.0 million in 2007 compared to $74.4 million in 2006. 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 - 2006 $ 12.7 $ 74.4
Increased electric revenue due to an
electricity price increase on April 1, 2007,
higher industrial sales volume, partially
offset by lower export sales volume; year to
date increase is also due to electricity
price increase in mid-March 2006, colder
weather, and increased residential and
commercial sales volume 29.3 108.9
Increased fuel expense (26.5) (118.3)
Increased regulatory amortization due to
the start of a new regulatory amortization
on April 1, 2007 (4.0) (8.0)
Decreased income taxes due to the income
tax recovery 10.8 10.8
Decreased income taxes primarily due to lower
taxable income 1.0 9.8
All other 1.7 (2.6)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2007 $ 25.0 $ 75.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q3 Electric Sales Volume Q3 Electric Sales Revenues
Gigawatt hours ("GWh") millions of dollars
----------------------------------- ------------------------------------
2007 2006 2005 2007 2006 2005
----------------------------------- ------------------------------------
Residential 771 763 783 Residential $ 95.8 $ 90.1 $ 85.1
Commercial 747 743 731 Commercial 72.7 70.0 63.8
Industrial 1,089 675 1,076 Industrial 70.0 44.8 61.2
Other 93 180 104 Other 10.7 15.0 11.4
----------------------------------- ------------------------------------
Total 2,700 2,361 2,694 Total $249.2 $219.9 $221.5
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Year-to-Date ("YTD") Electric YTD Electric Sales Revenues
Sales Volume millions of dollars
GWh
----------------------------------- ------------------------------------
2007 2006 2005 2007 2006 2005
----------------------------------- ------------------------------------
Residential 3,081 2,911 3,001 Residential $359.9 $324.4 $307.2
Commercial 2,368 2,281 2,276 Commercial 229.1 213.2 198.3
Industrial 3,145 1,949 3,176 Industrial 199.1 126.3 176.6
Other 266 565 292 Other 30.8 46.1 30.0
----------------------------------- ------------------------------------
Total 8,860 7,706 8,745 Total $818.9 $710.0 $712.1
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Q3 Average Revenue / Megawatt hour
("MWh")
-----------------------------------
2007 2006 2005
-----------------------------------
Dollars per
MWh $ 92 $ 93 $ 82
-----------------------------------
-----------------------------------
YTD Average Revenue / MWh
-----------------------------------
2007 2006 2005
-----------------------------------
Dollars per
MWh $ 92 $ 92 $ 81
-----------------------------------
-----------------------------------
Electric revenues increased by $29.3 million to $249.2 million in Q3 2007
compared to $219.9 million in Q3 2006. Revenue increases are substantially due
to increased sales volume due to a large industrial customer returning to
operations in late 2006, and a 3.8% rate increase effective April 1, 2007,
partially offset by lower export sales.
Year-to-date electric revenues increased by $108.9 million to
$818.9 million in 2007 from $710.0 million in 2006. Revenue increases are
substantially due to the 8.7% rate increase effective March 10, 2006 and a
3.8% rate increase effective April 1, 2007, increased sales volume due to a
large industrial customer returning to operations in late 2006, colder
weather, and increased residential and commercial sales volume, partially
offset by lower export sales.
The average revenue per MWh is lower in the quarter and unchanged year to
date reflecting the rate increases noted above, offset by a change in sales
mix, specifically the increase in lower priced industrial sales from the
return to operations of a large industrial customer.
Fuel for Generation and Purchased Power
Q3 Production Volume YTD Production Volume
GWh GWh
----------------------------------- ------------------------------------
2007 2006 2005 2007 2006 2005
----------------------------------- ------------------------------------
Coal & Coal &
petcoke 2,292 2,121 2,153 petcoke 7,042 6,760 6,835
Natural gas 315 122 67 Natural gas 724 262 162
Oil 4 - 336 Oil 470 257 1,139
Renewable 152 205 146 Renewable 693 765 755
Purchased Purchased
power 105 78 120 power 465 225 404
----------------------------------- ------------------------------------
Total 2,868 2,526 2,822 9,394 8,269 9,295
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Purchased power includes 27 GWh of Purchased power includes 111 GWh of
renewables in Q3 2007 renewables in 2007
(2006 - 20 GWh; 2005 - 15 GWh). (2006 - 76 GWh; 2005 - 54 GWh)
Q3 Average Unit Fuel Costs
-----------------------------------
2007 2006 2005
-----------------------------------
Dollars per
MWh $ 33 $ 27 $ 35
-----------------------------------
-----------------------------------
YTD Average Unit Fuel Costs
-----------------------------------
2007 2006 2005
-----------------------------------
Dollars per
MWh $ 34 $ 25 $ 32
-----------------------------------
-----------------------------------
Fuel for generation and purchased power increased $26.5 million to
$94.5 million in Q3 2007 compared to $68.0 million in Q3 2006. Year-to-date
fuel for generation and purchased power increased $118.3 million to
$323.4 million in 2007 compared to $205.1 million in 2006. 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 - 2006 $ 68.0 $ 205.1
Increased sales volume due to the return
to operation of a large industrial
customer that had been shut-down for
most of 2006, partially offset by lower
export sales; year to date increase is
also due to colder weather and increased
residential and commercial sales volume 21.5 89.7
Commodity price increases - 16.9
Decreased net proceeds from the resale of
natural gas 9.1 34.1
Deferral of fuel costs as discussed below - (3.0)
Decreased export sales volume (3.3) (11.6)
Changes in generation mix (0.2) (3.3)
All other (0.6) (4.5)
-------------------------------------------------------------------------
Fuel for generation and purchased
power - 2007 $ 94.5 $ 323.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Q3 and year-to-date average unit fuel costs increased in 2007 because
sales volume increases necessitated the use of higher marginal cost
production, and due to reductions in natural gas margins. A provision of the
2007 rate case settlement agreement allows NSPI to defer, for future recovery
in rates, up to $8 million of fuel costs should natural gas margins be less
than $47 million. Year to date 2007 NSPI deferred $3.0 million.
Regulatory Amortization
The UARB has approved recovery, over eight years, of a $147.1 million
regulatory asset related to pre-2003 income taxes that have been paid, but not
yet recovered from customers; and a $16.7 million regulatory asset related to
Q1 2005 taxes not previously included in rates. Amortization of these
regulatory assets began on April 1, 2007 and increased regulatory amortization
by $4.0 million in Q3 2007 and $8.0 million year-to-date 2007.
In Q3 2007, the regulatory asset related to pre-2003 income taxes was
reduced by the $14.6 million income tax recovery as discussed below.
Income Taxes
NSPI prepared and filed with CRA amended tax returns for the years 2000 to
2004 inclusive. CRA reviewed and approved the amended filings, which has
resulted in accelerated deductibility of certain capitalized expenses. NSPI
intends to amend tax returns for 2005 and 2006 using the same methodology and
will continue to use this methodology when filing its future tax returns. As a
result, NSPI has recorded an income tax recovery of $25.4 million, of which
$14.6 million has been recorded as a reduction of deferred charges,
specifically the regulatory asset related to its pre-2003 income tax
liability. The remaining $10.8 million has been recorded as a reduction of
current income tax expense. Refund interest has not been estimated on the
recovery as it is not reasonably determinable at this time.
Outlook
NSPI expects to earn within its allowed regulated return on equity for
2007. NSPI has also announced it will not file a general rate application for
2008.
BANGOR HYDRO-ELECTRIC COMPANY
All amounts in the Bangor Hydro section are reported in US dollars unless
otherwise stated.
Overview
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. BHE is a cost of service utility with an
alternate rate plan for its distribution operations.
The construction of the Northeast Reliability Interconnect ("NRI")
electricity transmission line was complete at the end of the quarter, and on
schedule to be in service in Q4 of this year. In Q2 2007, BHE filed updates to
its total project cost estimate with regulatory agencies and the Independent
System Operator in New England. The filing was based on BHE's total project
cost of $141 million, an approximate 20% increase over earlier estimates. The
change reflects higher costs of mitigating the effect of the line on the
Maritimes & Northeast Pipeline, with which it shares a utility corridor; and
increased construction costs due to a wet fall and short winter construction
season. The new cost estimate was incorporated into rates, which are
recognized in other revenue, effective June 1, 2007.
Leadership
Effective October 5, 2007 Robert J.S. Hanf was appointed President and
Chief Operating Officer for Bangor Hydro. Prior to his position with Bangor
Hydro, Mr. Hanf acted as General Counsel for Emera Inc., and its affiliates,
where he and his internal legal team provided legal and regulatory services to
Emera and its various operating subsidiaries in Canada and the Northeast
United States. Before joining Emera in 2002, he was Partner in the law firm of
McCarthy Tetrault LLP, Calgary, Alberta, specializing in energy law.
Review of 2007
Bangor Hydro Q3 Net Earnings
millions of dollars
(except earnings Three months ended Nine months ended
per common share) September 30 September 30
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
T&D electric revenues $ 25.3 $ 26.5 $ 75.8 $ 76.3
Resale of purchased power 3.1 3.6 10.9 11.5
Other revenue 6.2 - 8.2 -
-------------------------------------------------------------------------
Total revenue 34.6 30.1 94.9 87.8
Purchased power and fuel
for generation 7.2 6.7 23.6 23.2
Operating, maintenance and
general 6.3 6.3 18.3 20.1
Property taxes 1.0 1.3 4.0 4.0
Depreciation 3.3 3.2 9.8 9.7
Regulatory amortization 3.6 4.4 10.0 10.6
Other (3.2) (1.4) (8.6) (3.8)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 16.4 9.6 37.8 24.0
Interest 3.3 2.4 9.3 7.6
-------------------------------------------------------------------------
Earnings before income
taxes 13.1 7.2 28.5 16.4
Income taxes 4.4 2.6 9.5 6.2
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings - USD $ 8.7 $ 4.6 $ 19.0 $ 10.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings - CAD $ 9.1 $ 5.1 $ 20.8 $ 11.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share - CAD $ 0.09 $ 0.05 $ 0.19 $ 0.11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted
average foreign exchange
rate - CAD/USD $ 1.04 $ 1.11 $ 1.09 $ 1.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings increased by $4.1
million to $8.7 million in Q3 2007 compared to $4.6 million in Q3 2006. Year
to date Bangor Hydro's contribution to consolidated net earnings increased
$8.8 million to $19.0 million in 2007 compared to $10.2 million in 2006.
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 - 2006 $ 4.6 $ 10.2
Other revenue associated with the recovery
of the NRI project beginning in June 2007 6.2 8.2
Increased overheads and AFUDC capitalized
primarily as a result of capital
expenditures on the NRI transmission
project 1.3 4.7
Increased income taxes due to increased
earnings (1.8) (3.3)
All other (1.6) (0.8)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2007 $ 8.7 $ 19.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's increased contribution to consolidated net earnings in CAD
was partially offset by the $0.6 million effect of the stronger Canadian
dollar in the quarter and the $0.7 million effect of the stronger Canadian
dollar year to date.
Electric Revenue
Q3 Electric Sales Volume Q3 Electric Sales Revenues
GWh millions of dollars
----------------------------------- ------------------------------------
2007 2006 2005 2007 2006 2005
----------------------------------- ------------------------------------
Residential 141 144 146 Residential $ 11.7 $ 12.1 $ 12.2
Commercial 161 164 167 Commercial 9.5 9.8 9.2
Industrial 103 91 109 Industrial 2.7 2.6 3.6
Other 3 3 3 Other 1.4 2.0 1.3
----------------------------------- ------------------------------------
Total 408 402 425 Total $ 25.3 $ 26.5 $ 26.3
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
YTD Electric Sales Volume YTD Electric Sales Revenues
GWh millions of dollars
----------------------------------- ------------------------------------
2007 2006 2005 2007 2006 2005
----------------------------------- ------------------------------------
Residential 437 434 446 Residential $ 36.6 $ 36.2 $ 38.1
Commercial 457 457 463 Commercial 27.5 27.3 28.0
Industrial 277 279 304 Industrial 8.4 8.5 9.6
Other 9 9 9 Other 3.3 4.3 3.9
Total 1,180 1,179 1,222 Total $ 75.8 $ 76.3 $ 79.6
----------------------------------- ------------------------------------
Q3 Average Revenue / MWh
-----------------------------------
2007 2006 2005
-----------------------------------
Dollars per
MWh $ 62 $ 66 $ 62
-----------------------------------
-----------------------------------
YTD Average Revenue / MWh
-----------------------------------
2007 2006 2005
-----------------------------------
Dollars per
MWh $ 64 $ 65 $ 65
-----------------------------------
-----------------------------------
Other Revenue
Other revenue was $6.2 million in Q3 2007 and $8.2 million year to date
2007, which resulted from the recovery of NRI projects costs, starting in June
2007, from the New England Power Pool.
Depreciation associated with the NRI project will begin in Q4 2007 when
the NRI project goes into service.
Interest Expense
Interest expense increased $0.9 million to $3.3 million in Q3 2007
compared to $2.4 million in Q3 2006 and increased $1.7 million to $9.3 million
in 2007 compared to $7.6 million in 2006 primarily due to increased debt used
to finance the NRI project.
Other
Other recoveries increased $1.8 million to $3.2 million in Q3 2007
compared to $1.4 million in Q3 2006 and increased $4.8 million to $8.6 million
in 2007 compared to $3.8 million in 2006 due to increased AFUDC related to the
NRI project.
OTHER
All activities of Emera other than its two wholly-owned regulated electric
utilities are incorporated into Other, including:
- Bear Swamp, a 50/50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts. Bear Swamp typically
pumps water into its reservoir using lower priced off-peak power, and
uses that hydro capacity to generate electricity during higher priced
on-peak periods.
- Emera Energy Services, a wholly owned subsidiary, which purchases and
sells natural gas and electricity on behalf of third parties and
provides related energy asset management services. Emera Energy
Services operates with minimal day-to-day commodity risk exposure.
Volatility in natural gas markets usually results in increased
opportunities for Emera Energy Services.
- Brunswick Pipeline, a 145 kilometer greenfield pipeline project under
development that 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 project is expected to
be in service as targeted by the end of 2008.
- A 12.9% interest in the $2 billion, 1,400 kilometer Maritimes &
Northeast Pipeline that transports Nova Scotia's offshore natural gas
to markets in Maritime Canada and the northeastern United States.
- A 19% interest in St. Lucia Electricity Services ("Lucelec"), a
vertically integrated electric utility on the Caribbean Island of
St. Lucia, which was acquired in January 2007. Additional details are
provided below.
- 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 St. Lucia Electricity Services
St. Lucia Electricity Services Limited is a vertically integrated electric
utility serving more than 50,000 customers on the Caribbean island of St.
Lucia. Emera acquired a 19% equity interest in Lucelec for $22 million USD in
January 2007.
Lucelec has an exclusive license to generate, transmit and distribute
electricity on the island to 2045. The utility has 77 MW of generating
capacity, primarily oil fired, and 800 kilometers of electricity transmission
and distribution assets. Lucelec is a cost of service utility, with a minimum
rate of return of 10% on a 50% equity base. Emera financed the acquisition
with existing credit facilities. Lucelec is expected to add approximately
$1 million - $2 million to Emera's annual consolidated net earnings.
Emera's strategy recognizes that the Caribbean market has attractive
growth prospects and opportunities for the company to deploy its operational
expertise. This modest investment in Lucelec provides Emera with a low risk
vehicle to assess whether there is broader business potential for the company
in the region, and at the same time, provides immediately accretive and
attractive returns.
Review of 2007
Other Q3 Net Earnings
millions of dollars
(except earnings Three months ended Nine months ended
per common share) September 30 September 30
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Bear Swamp earnings
before interest and
taxes ("EBIT") $ 5.1 $ 0.4 $ 15.1 $ 2.2
Emera Energy Services
EBIT 2.3 5.1 10.3 10.5
M&NP equity earnings 2.1 1.2 8.0 3.7
Lucelec equity earnings 0.5 - 1.3 -
Corporate costs and other (2.3) (2.5) (9.6) (6.0)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 7.7 4.2 25.1 10.4
Interest 0.8 2.5 5.0 6.4
-------------------------------------------------------------------------
Earnings before income
taxes 6.9 1.7 20.1 4.0
Income taxes 0.1 - 1.2 (2.4)
-------------------------------------------------------------------------
Contribution to conso-
lidated net earnings $ 6.8 $ 1.7 $ 18.9 $ 6.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to conso-
lidated earnings per
common share $ 0.06 $ 0.02 $ 0.17 $ 0.06
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The contribution of Other to consolidated net earnings increased
$5.1 million to $6.8 million in Q3 2007 compared to $1.7 million in Q3 2006.
The year-to-date contribution of Other to consolidated net earnings increased
$12.5 million to $18.9 million in 2007 compared to $6.4 million in 2006.
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 - 2006 $ 1.7 $ 6.4
Increased Bear Swamp EBIT due to
increased energy and capacity sales 2.8 6.9
Increased Bear Swamp EBIT due to
changes in mark-to-market positions 1.9 6.0
Decreased Emera Energy Services EBIT
as a result of changes in supply,
market performance,and a stronger
Canadian dollar (2.8) (0.2)
Increased M&NP equity earnings due to
expansion costs that were expensed
throughout 2006 and capitalized
in Q1 2007 0.9 4.3
Equity earnings from Lucelec 0.5 1.3
Increased year-to-date corporate
costs due primarily to increased
business development activity 0.2 (3.6)
Increased income taxes related to
increased earnings (0.1) (3.6)
All other 1.7 1.4
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2007 $ 6.8 $ 18.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bear Swamp
During Q2, Bear Swamp completed a $125 million USD financing using a
senior secured non-revolving credit facility. The five-year credit facility
bears interest at a LIBOR-based facility rate, is secured by the assets of
Bear Swamp, and is due in May 2012. Proceeds of the financing were distributed
equally to Emera and Brookfield Power.
During Q1, Bear Swamp finalized a long-term agreement with the Long Island
Power Authority ("LIPA") providing LIPA with 345 MW of capacity to May 31,
2010 (approximately 55% of Bear Swamp's total capacity); and 100 MW
thereafter, to April 30, 2021. In addition, Bear Swamp will provide LIPA with
12,200 MWh of super-peak and peak energy weekly, (approximately 35% of the
plant's available energy) at a fixed price, with an annual increase, over the
14 year term of the agreement. Bear Swamp has contracted with its parent
companies, Emera and Brookfield Power for the power supply necessary to
produce the requirements of the LIPA agreement.
Brunswick Pipeline
The National Energy Board ("NEB") issued a Certificate of Public
Convenience and Necessity on June 11, 2007 reflecting approval for the project
from both the Governor in Council and the NEB. There are no outstanding
appeals. The project continues to progress on track with Right of Way
acquisition and construction planning. Clearing will begin in November 2007
and the pipeline is expected to be in service as targeted by the end of 2008.
Consolidated Balance Sheets
Significant changes in the consolidated balance sheets between
September 30, 2007 and December 31, 2006 include:
Increase
millions of dollars (Decrease) Explanation
-------------------------------------------------------------------------
Assets
Accounts receivable $57.8 Lower accounts receivable securitized,
higher sales due to a rate increase and
a higher receivable from a natural gas
supplier in NSPI, partially offset by a
decrease in Emera Energy Services due to
decreased trading activity, a stronger
Canadian dollar and lower commodity
prices.
Income tax receivable 31.0 Income tax recovery in NSPI.
Prepaid expenses (11.3) Decreased posted margin paid to
counterparties and a stronger Canadian
dollar in Emera Energy Services.
Derivatives in a valid 25.3 Implementation of new accounting
hedging relationship standards related to financial
(including long-term instruments and hedges. Balance
portion) primarily represents the fair value of
NSPI's hedges.
Held for trading 99.9 Implementation of new accounting
derivatives (including standards related to financial
long-term portion) instruments and hedges. Balance
represents the fair value of certain of
NSPI's natural gas contracts, trading
instruments in Emera Energy Services,
and instruments held by NSPI that are
not considered valid hedges.
Deferred charges (84.4) As a result of implementing new
accounting standards, reclassification
of deferred financing costs, now netted
against long-term debt. An income tax
recovery in NSPI, ongoing and new
amortizations, lower accounts receivable
securitized in NSPI, and a stronger
Canadian dollar also contributed to the
decrease.
Goodwill (13.6) Stronger Canadian dollar.
Investments subject to 20.3 Q1 2007 investment in Lucelec
significant influence
------------------------------------------------------------------------
Liabilities and
Shareholders' Equity
Short-term debt 67.2 Increased issuance of short-term notes
in NSPI and increased borrowings to
finance the NRI project in Bangor Hydro.
Accounts payable (65.3) Timing of payments in NSPI,and reduced
and accrued charges trading activity, a stronger Canadian
dollar, along with lower commodity
prices in Emera Energy Services.
Income tax payable (37.0) Increased installments in NSPI.
Derivatives in a valid 86.8 Implementation of new accounting
hedging relationship standards related to financial
(including long-term instruments and hedges. Balance
portion) primarily represents the fair value of
NSPI's hedges.
Held for trading (10.1) Implementation of new accounting
derivatives (including standards related to financial
long-term portion) instruments and hedges. Balance
represents the fair value of certain of
NSPI's natural gas contracts, trading
instruments in Emera Energy Services,
and instruments held by NSPI that are
not considered valid hedges.
Deferred credits 93.4 Implementation of new accounting
standards. Change primarily represents
the new regulatory liability recognized
in NSPI as a result of fair valuing
certain natural gas contracts partially
offset by the effect of a stronger
Canadian dollar in Bangor Hydro.
Long-term debt 53.2 Increased borrowing in Bangor Hydro and
(including current Bear Swamp partially offset by the
portion) netting of deferred financing costs
against long-term debt as a result of
implementing new accounting standards,
and a stronger Canadian dollar.
Accumulated other (121.1) Implementation of new accounting
comprehensive income standards related to financial
instruments, hedges, and comprehensive
income. Balance represents the effective
portion of the fair value of NSPI's
hedges and the cumulative foreign
exchange translation loss on foreign
self-sustaining operations. Change
primarily represents the effect of the
strengthening Canadian dollar relative
to NSPI's existing foreign exchange
hedges and on the company's investment
in Bangor Hydro.
Retained earnings 37.5 Net earnings in excess of dividends
paid.
-------------------------------------------------------------------------
Additional information on the new accounting standards is outlined in the
Changes in Accounting Policies section below.
Outstanding Share Data
Common Share
Capital
Millions of millions of
Issued and Outstanding: Shares dollars
-------------------------------------------------------------------------
January 1, 2006 110.10 $1,039.2
Issued for cash under purchase plans 0.45 8.6
Options exercised under senior management
share option plan 0.38 6.7
Share-based compensation - 0.7
-------------------------------------------------------------------------
December 31, 2006 110.93 $1,055.2
Issued for cash under purchase plans 0.35 7.2
Options exercised under senior management
share option plan 0.08 1.6
Share-based compensation - 0.2
-------------------------------------------------------------------------
September 30, 2007 111.36 $1,064.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at October 19, 2007 the number of issued and outstanding common shares
was 111.40 million.
Liquidity and Capital Resources
Emera and Nova Scotia Power's debt shelf prospectuses in the amounts of
$300 million and $400 million respectively expired in April 2007 and will be
renewed by the end of 2007.
North American financial markets have experienced significant volatility
in Q3 due to ongoing U.S. sub-prime mortgage concerns. This has pressured
global debt markets and in turn affected the Canadian asset-backed commercial
paper market. Emera and its subsidiaries have no investments in asset-backed
commercial paper. Nova Scotia Power issues commercial paper to finance
short-term cash requirements and has been able to continue to access the
market as required.
During Q3, BHE completed a $50 million USD financing using senior
unsecured promissory notes. Proceeds were used to pay down a $40 million USD
interim bank credit line used as a bridge financing, and short-term debt.
During Q2, Bear Swamp completed a $125 million USD financing using a
senior secured non-revolving credit facility. The five-year credit facility
bears interest at a LIBOR-based facility rate, is secured by the assets of
Bear Swamp, and is due in May 2012. Proceeds of the financing were distributed
equally to Emera and Brookfield Power.
Consolidated Cash Flow Highlights
Significant changes in the consolidated cash flow statements between
September 30, 2007 and September 30, 2006 include:
Three months ended
September 30
millions of dollars 2007 2006 Explanation
-------------------------------------------------------------------------
Cash and cash equivalents,
beginning of period $ 8.3 $ 26.4
Provided by (used in):
Operating activities 82.8 98.8 In 2007, cash earnings
partially offset by increased
non-cash working capital.
In 2006, cash earnings and
decreased non-cash working
capital.
Investing activities (80.0) (57.4) In 2007, capital spending,
including NRI and Brunswick
Pipeline projects.
In 2006, capital spending,
including NRI.
Financing activities (2.5) (63.3) In 2007, dividends on common
shares offset by increased
debt levels.
In 2006, decreased debt
levels and dividends on
common shares.
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 8.6 $ 4.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended
September 30
millions of dollars 2007 2006 Explanation
-------------------------------------------------------------------------
Cash and cash equivalents,
beginning of period $ 7.6 $ 21.5
Provided by (used in):
Operating activities 153.4 239.1 In 2007, cash earnings
partially offset by increased
non-cash working capital.
In 2006, cash earnings.
Investing activities (197.2) (120.0) In 2007, capital spending,
including NRI and Brunswick
Pipeline projects, and
acquisition of 19% interest
in Lucelec.
In 2006, capital spending,
including NRI.
Financing activities 44.8 (136.1) In 2007, increased debt
levels, partially offset by
dividends on common shares
and decreased accounts
receivable securitized.
In 2006, dividends on common
shares, decreased debt
levels, and decreased
accounts receivable
securitized.
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 8.6 $ 4.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial and Commodity Instruments
The company enters into swap contracts on commodities to limit exposure to
(hedge) fluctuations in natural gas and oil prices; foreign exchange forwards,
options and swap contracts to hedge currency rate fluctuations; and interest
rate contracts to hedge interest rate fluctuations. In addition, the company
has contracts for physical purchases and sales of natural gas. Collectively,
these contracts are referred to as derivatives.
Derivatives that meet stringent documentation requirements, and can be
proven to be effective hedges both at the inception and over the term of the
derivative qualify for hedge accounting. That enables amounts paid or received
to be deferred and recognized in earnings in the same period that the related
hedged item is realized.
As a result of implementing new accounting standards related to financial
instruments and hedges in 2007, the company is recognizing the fair value of
derivatives in valid hedging relationships on its balance sheet. Further, the
effective portion of the hedging relationship is recognized in other
comprehensive income. Any ineffective portion of the hedging relationship is
recognized in net earnings in the reporting period. The total ineffectiveness
recognized by the company was a $0.2 million gain in Q3 2007 and no gain or
loss recognized year-to-date 2007.
Amounts paid or received in connection with derivatives that do not
qualify as hedges are in net earnings in the period.
Derivatives held for trading are recorded on the balance sheet at fair
value, with changes normally recorded in net earnings of the period, unless
deferred as a result of regulatory accounting.
Where the documentation or effectiveness requirements are not met, the
derivative instruments are recognized at fair value with any changes in fair
value recognized in net earnings in the reporting period.
The company has the following categories on the balance sheet related to
derivatives in valid hedging relationships:
Hedging Items Recognized on the Balance Sheet
millions of dollars
-------------------------------------------------------------------------
September 30 December 31
2007 2006
-------------------------------------------------------------------------
Inventory $ 4.2 $ 5.2
Derivatives in a valid hedging relationship (61.5) -
Long-term debt 0.7 -
Deferred charges - 0.9
-------------------------------------------------------------------------
$ (56.6) $ 6.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three and nine month periods ended September 30, the impacts of
derivatives in valid hedging relationships 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
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Fuel and purchased power
(increase) decrease $ (8.9) $ 9.6 $ (18.2) $ 30.2
Interest expense increase (0.1) (0.1) (0.3) (0.2)
-------------------------------------------------------------------------
Hedging earnings impact $ (9.0) $ 9.5 $ (18.5) $ 30.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Held for Trading Items Recognized on the Balance Sheet
The company has recognized a net unrealized fair value of held for trading
derivatives of $111.2 million (December 31, 2006 - $1.2 million) on the
balance sheet. The company has recognized the following realized and
unrealized gains and losses with respect to held for trading derivatives in
earnings:
Held for Trading Derivatives
Gains (Losses) Recognized in
Earnings Three months ended Nine months ended
millions of dollars September 30 September 30
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Electric revenue $ 0.5 $ (2.4) $ 0.9 $ (2.5)
Other revenue 4.0 5.9 21.4 14.5
Fuel and purchased power 2.1 - (0.5) -
-------------------------------------------------------------------------
Held for trading
derivatives gains $ 6.6 $ 3.5 $ 21.8 $ 12.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $5.9 million (2006 - $7.4 million) during the
three months ended September 30, 2007 and $20.3 million (2006 - $23.1 million)
during the nine months ended September 30, 2007 from the Maritimes & Northeast
Pipeline, an investment under significant influence of the company. The amount
is recognized in fuel for generation and purchased power or netted against
energy marketing margin in other revenue, and is measured at the exchange
amount. As at September 30, 2007 the amount payable to the related party is
$3.9 million (December 31, 2006 - $3.4 million), is non-interest bearing and
is under normal credit terms.
Changes in Accounting Policies
The Canadian Institute of Chartered Accountants ("CICA") has introduced
new classification and measurement requirements for financial instruments,
including increased use of fair value measurement. These new accounting
standards are incorporated in CICA Handbook Sections 1530 Comprehensive
Income, 3855 Financial Instruments - Recognition and Measurement, and
3865 Hedges, and are effective as of January 1, 2007 for Emera Inc.
In accordance with the new accounting standards, the accounting policy
changes were applied retroactively without restatement of prior periods. The
following provides more information on each standard.
Comprehensive Income
As a result of the recently issued standard, a new item, accumulated other
comprehensive income ("AOCI"), is recognized in the shareholders' equity
section of the consolidated balance sheets. AOCI includes the unrealized
foreign exchange translation adjustments on the company's self-sustaining
foreign operations, the effective portion of changes in fair value of
derivatives meeting the requirements for cash flow hedges, and unrealized
gains and losses on financial assets classified as available-for-sale.
Financial Instruments - Recognition and Measurement
According to the new standard, financial assets are now classified as
loans and receivables, held for trading, available for sale, or held to
maturity. Financial liabilities are classified as either held for trading, or
other than held for trading. The financial assets and liabilities are subject
to different methods of measurement and classification in the financial
statements, as set out in the accompanying table:
-------------------------------------------------------------------------
Financial Instrument Measured at Classified in
-------------------------------------------------------------------------
- Loans and receivables Amortized cost N/A
- Held to maturity financial
assets
- Other than held for trading
financial liabilities
-------------------------------------------------------------------------
- Held for trading financial Fair value Net earnings unless
assets and liabilities deferral permitted under
regulatory accounting
-------------------------------------------------------------------------
- Available for sale financial Fair value Other comprehensive
assets income
-------------------------------------------------------------------------
In accordance with the new standard, transaction costs associated with the
issuance of long-term debt are included in long-term debt and amortized using
the effective interest method.
Hedges
The new standard outlines the criteria for applying hedge accounting to
cash flow hedges, fair value hedges, and hedging foreign currency fluctuations
on self-sustaining foreign operations.
Cash flow hedges are recognized on the balance sheet at fair value with
the effective portion of the hedging relationship recognized in other
comprehensive income. Any ineffective portion of the cash flow hedge is
recognized in net earnings. Amounts recognized in AOCI are reclassified to net
income in the same periods in which the hedged item is recognized in net
earnings.
Fair value hedges and the related hedged items are recognized on the
balance sheet at fair value with any changes in fair value recognized in net
income. To the extent the fair value hedge is effective, the changes in fair
value of the hedge and the hedged item will offset each other.
Hedges of self-sustaining foreign operations are recognized at fair value
with any changes in fair value recognized in other comprehensive income.
Accounting for the impact of rate-regulation:
In accordance with the new accounting standards as outlined above,
Nova Scotia Power determined that its contracts for the purchase or sale of
natural gas for its Tufts Cove generating station ("TUC") should be considered
derivative financial instruments and accordingly recognized at fair value as a
held for trading ("HFT") asset or liability as applicable. This reflects
NSPI's history of buying and reselling any natural gas not used in the
production of electricity at TUC.
Changes in the fair value of HFT assets and liabilities are recognized in
net earnings. In accordance with Nova Scotia Power's accounting policy
covering physical and financial contracts relating to fuel at TUC, NSPI has
deferred any changes in fair value to a regulatory asset or liability as
appropriate, which are reflected in deferred assets or credits. Upon
implementation of these accounting standards at January 1, 2007, the fair
value of these contracts was $171.9 million. Absent this accounting policy,
which has been approved by the UARB, retained earnings would have increased by
$171.9 million at January 1, 2007. As of September 30, 2007, the fair value of
the HFT asset and liability was $97.8 million. Absent this accounting policy,
the decrease of $74.1 million ($45.9 million after-tax) would have decreased
NSPI's year to date earnings.
Details of the amounts recognized upon implementation of the new
accounting standards, and the effect on the consolidated balance sheet as at
January 1, 2007 are summarized below:
Consolidated
Balance Sheet Balance Before Effect of Balance After
Selected Information Implementation Implementation Implementation
millions of dollars Adjustment Adjustment Adjustment
-------------------------------------------------------------------------
Current assets
Energy marketing assets $ 37.3 $ (37.3) -
Derivatives in valid
hedging relationship - 13.9 $ 13.9
Held for trading derivatives - 76.0 76.0
Energy marketing assets 2.0 (2.0) -
Derivatives in a valid hedging
relationship - 17.9 17.9
Held for trading derivatives - 136.4 136.4
Deferred charges 468.2 (11.3) 456.9
Investments 98.5 (98.5) -
Investments subject to
significant influence - 98.5 98.5
-------------------------------------------------------------------------
$ 193.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities
Current portion of long-term
debt $ 3.4 $ (0.2) $ 3.2
Energy marketing liabilities 36.7 (36.7) -
Derivatives in a valid hedging
relationship - 26.6 26.6
Held for trading derivatives - 39.7 39.7
Energy marketing liabilities 1.4 (1.4) -
Derivatives in a valid hedging
relationship - 10.6 10.6
Held for trading derivatives - 2.6 2.6
Deferred credits 66.1 173.1 239.2
Long-term debt 1,657.4 (12.7) 1,644.7
Shareholders' equity
Foreign exchange translation
adjustment (100.2) 100.2 -
Accumulated other
comprehensive income - (105.5) (105.5)
Retained earnings 450.9 (2.7) 448.2
-------------------------------------------------------------------------
$ 193.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The effect on the January 1, 2007 balances can be further explained as
follows:
Energy marketing assets and liabilities: The balances have been
reclassified to held for trading derivatives.
Derivatives in a valid hedging relationship: This new account represents
the fair value of Nova Scotia Power's hedges. These derivatives are all
designated as hedging future expected cash flows.
Held for trading derivatives: This new account includes the fair value of
certain of Nova Scotia Power's natural gas contracts, amounts previously
recognized as energy marketing assets and liabilities, and the fair value of
any derivatives that are not considered valid hedges.
Deferred charges: The adjustment represents the reclassification of
deferred financing costs which are now netted against the related debt,
partially offset by the regulatory asset resulting from the fair value
recognition of certain of Nova Scotia Power's natural gas contracts.
Investments: The adjustment represents the reclassification of equity
accounted investments to investments subject to significant influence.
Investments subject to significant influence: This new account represents
the reclassification of equity accounted investments from the investments
account as noted above.
Deferred credits: The adjustment represents the regulatory liability
resulting from the fair value recognition of certain of Nova Scotia Power's
natural gas contracts.
Long-term debt (including current portion): The adjustment represents the
netting of deferred financing costs against the related debt.
Foreign exchange translation adjustment: The adjustment represents the
reclassification of foreign exchange losses on self-sustaining foreign
operations to accumulated other comprehensive income.
Accumulated other comprehensive income: The adjustment represents the
effective portion of the fair value of Nova Scotia Power's hedges and the
cumulative foreign exchange loss on self-sustaining foreign operations.
Retained earnings: The adjustment represents the fair value of Bear
Swamp's interim LIPA contract.
As a result of implementing the accounting policy changes, earnings have
increased by $0.2 million ($0.1 million after-tax) in Q3 2007 and $2.7 million
($1.6 million after-tax) year to date 2007, which represents the change in
fair value of Bear Swamp's interim LIPA contract and the ineffective portion
of the company's hedges. There has been no effect on the consolidated
statement of changes of cash flow.
The fair value of derivatives held in a valid hedging relationship and
held for trading derivatives are estimated by obtaining prevailing market
rates from investment dealers.
Future Accounting Policy Changes
The CICA has issued new accounting standards 1535 Capital Disclosures,
3031 Inventories, 3862 Financial Instruments - Disclosures, and 3863 Financial
Instruments - Presentation which are applicable to Emera's 2008 fiscal year.
The following provides more information on each new accounting standard.
Capital Disclosures: This new standard requires disclosure of the
company's objectives, policies, and processes for managing capital;
quantitative data about what the company regards as capital; whether the
company has complied with capital requirements; and, if the company has not
complied, the consequences of such non-compliance. The new accounting standard
covers disclosure only and will have no effect on the financial results of the
company.
Inventories: The new standard provides more guidance on the measurement
and disclosure requirements for inventories than the previous standard,
3030 Inventories. Specifically, the new standard requires that inventories be
measured at the lower of cost and net realizable value, and provides more
guidance on the determination of cost and its subsequent recognition as an
expense, including any write-down to net realizable value. The company is
assessing the effect of the new standard on its financial results but does not
anticipate any material effect on its results.
Financial Instruments - Disclosures and Financial Instruments -
Presentation: These new standards replace accounting standard 3861 Financial
Instruments - Disclosure and Presentation. Presentation requirements have not
changed. Enhanced disclosure is required to assist users of the financial
statements in evaluating the significance of financial instruments on the
company's financial position and performance, including qualitative and
quantitative information about the company's exposure to risks arising from
financial instruments. The new accounting standards cover disclosure only and
will have no effect on the financial results of the company.
Dividends
In July 2007, the Board of Directors approved a quarterly dividend of
$0.2275 per common share, reflecting an increase on an annualized basis to
$0.91 from $0.89.
Summary of Quarterly Reports
For the quarter ended
millions of dollars (except earnings per common share)
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4
2007 2007 2007 2006
-------------------------------------------------------------------------
Total revenues $ 310.3 $ 325.4 $ 359.9 $ 307.0
-------------------------------------------------------------------------
Net earnings applicable
to common shares 40.9 34.1 39.7 33.5
-------------------------------------------------------------------------
Earnings per common share
- basic 0.37 0.30 0.36 0.30
-------------------------------------------------------------------------
Earnings per common share
- diluted 0.35 0.30 0.35 0.30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4
2006 2006 2006 2005
-------------------------------------------------------------------------
Total revenues $ 272.4 $ 275.9 $ 310.7 $ 297.1
-------------------------------------------------------------------------
Net earnings applicable
to common shares 19.5 29.2 43.6 37.7
-------------------------------------------------------------------------
Earnings per common share
- basic 0.18 0.26 0.40 0.34
-------------------------------------------------------------------------
Earnings per common share
- diluted 0.18 0.26 0.38 0.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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)
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For the
millions of dollars (except Three months ended Six months ended
earnings per common share) September 30 September 30
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2007 2006 2007 2006
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Revenue
Electric $ 290.3 $ 261.1 $ 947.5 $ 830.4
Other 20.0 11.3 48.1 28.6
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310.3 272.4 995.6 859.0
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Cost of operations
Fuel for generation and
purchased power (note 6) 109.5 81.2 370.5 245.4
Operating, maintenance,
and general 64.9 66.2 193.3 190.6
Provincial, state, and
municipal taxes 11.6 12.2 36.1 36.3
Depreciation 36.8 36.1 111.2 108.3
Regulatory amortization 9.2 6.4 23.6 16.6
Allowance for funds used
during construction (3.5) (1.4) (9.1) (3.7)
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228.5 200.7 725.6 593.5
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Earnings from operations 81.8 71.7 270.0 265.5
Equity earnings 2.6 1.2 9.3 3.7
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Earnings before interest and
income taxes 84.4 72.9 279.3 269.2
Interest (note 8) 32.5 32.2 94.3 92.9
Amortization of defeasance
costs 3.2 3.2 9.5 9.5
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Earnings before income taxes 48.7 37.5 175.5 166.8
Income taxes (note 9) 4.5 14.7 50.8 64.5
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Net earnings before
non-controlling interest 44.2 22.8 124.7 102.3
Non-controlling interest 3.3 3.3 10.0 10.0
Net earnings applicable to
common shares $ 40.9 $ 19.5 $ 114.7 $ 92.3
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Earnings per common share
- basic $ 0.37 $ 0.18 $ 1.03 $ 0.84
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Earnings per common share
- diluted $ 0.35 $ 0.18 $ 1.00 $ 0.82
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See accompanying notes to the unaudited consolidated financial
statements.
Weighted average number of common
shares outstanding (millions)
- basic 111.3 110.6 111.2 110.4
- diluted (note 11) 125.1 110.6 124.5 116.8
Consolidated Balance Sheets (Unaudited)
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As at September 30 December 31
millions of dollars 2007 2006
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Assets
Current assets
Cash and cash equivalents $ 8.6 $ 7.6
Restricted cash 4.0 11.9
Accounts receivable 311.4 253.6
Income tax receivable 36.3 5.3
Inventory 104.8 113.6
Prepaid expenses 42.6 53.9
Future income tax assets 9.5 18.9
Derivatives in a valid hedging relationship
(note 3) 23.3 -
Held for trading derivatives (note 3) 60.7 37.3
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601.2 502.1
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Derivatives in a valid hedging relationship
(note 3) 2.0 -
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Held for trading derivatives (note 3) 78.5 2.0
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Deferred charges (note 3) 383.8 468.2
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Future income tax assets 19.3 10.0
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Goodwill 83.5 97.1
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Investments subject to significant influence
(note 3) 118.8 98.5
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Property, plant and equipment 2,678.5 2,756.4
Construction work in progress 209.6 125.5
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2,888.1 2,881.9
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$ 4,175.2 $ 4,059.8
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Liabilities and Shareholders' Equity
Current liabilities
Current portion of long-term debt
(notes 3 and 10) $ 122.2 $ 3.4
Short-term debt 200.4 133.2
Accounts payable and accrued charges 220.7 286.0
Income tax payable 2.3 39.3
Dividends payable 3.2 3.2
Future income tax liabilities 3.4 -
Derivatives in a valid hedging relationship
(note 3) 43.4 -
Held for trading derivatives (note 3) 20.7 36.7
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616.3 501.8
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Derivatives in a valid hedging relationship
(note 3) 43.4 -
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Held for trading derivatives (note 3) 7.3 1.4
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Future income tax liabilities 81.2 86.2
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Asset retirement obligations 81.1 78.1
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Deferred credits (note 3) 159.5 66.1
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Long-term debt (notes 3 and 10) 1,591.8 1,657.4
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Non-controlling interest 260.6 260.7
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Shareholders' equity
Common shares (note 11) 1,064.2 1,055.2
Contributed surplus 2.7 2.2
Accumulated other comprehensive income (note 3) (221.3) (100.2)
Retained earnings 488.4 450.9
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1,334.0 1,408.1
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$ 4,175.2 $ 4,059.8
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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
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2007 2006 2007 2006
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Operating activities
Net earnings before
non-controlling
interest $ 44.2 $ 22.8 $ 124.7 $ 102.3
Non-cash items:
Depreciation 36.8 36.1 111.2 108.3
Amortization of deferred
charges 3.6 3.6 10.6 10.4
Equity earnings (2.6) (1.2) (9.3) (3.7)
Regulatory amortization 9.2 6.4 23.6 16.6
Allowance for funds used
during construction (3.5) (1.4) (9.1) (3.7)
Future income taxes 1.3 2.1 5.2 6.1
Post-retirement benefits 4.0 (0.4) 11.1 6.5
Reduction in regulatory
asset (note 9) 14.6 - 14.6 -
Other non-cash operating
items (6.1) (4.5) (13.0) (3.7)
Other cash operating items 0.4 1.5 1.6 2.0
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101.9 65.0 271.2 241.1
Change in non-cash operating
working capital (19.1) 33.8 (117.8) (2.0)
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Net cash provided by
operating activities 82.8 98.8 153.4 239.1
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Investing activities
Property, plant and
equipment (81.9) (52.9) (176.9) (109.7)
Acquisition (note 4) - - (25.7) -
Retirement spending net
of salvage (0.7) (0.6) (2.2) (2.2)
Decrease (increase) in
restricted cash 2.9 (4.3) 7.9 (8.5)
Other investing activities (0.3) 0.4 (0.3) 0.4
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Net cash used in investing
activities (80.0) (57.4) (197.2) (120.0)
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Financing activities
Retirement of long-term debt (1.0) - (2.0) (150.8)
Issuance of long-term debt 50.2 - 117.1 40.0
(Decrease) increase in
short-term debt (24.6) (41.8) 62.8 76.5
Issuance of common shares 2.6 6.0 8.8 12.1
Dividends on common shares (25.1) (24.5) (74.5) (73.6)
Dividends paid by
subsidiaries to
non-controlling interest (3.3) (3.3) (10.0) (10.0)
Accounts receivable
securitization - - (55.0) (30.0)
Other financing (1.3) 0.3 (2.4) (0.3)
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Net cash (used in) provided
by financing activities (2.5) (63.3) 44.8 (136.1)
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Increase (decrease) in cash
and cash equivalents 0.3 (21.9) 1.0 (17.0)
Cash and cash equivalents,
beginning of period 8.3 26.4 7.6 21.5
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Cash and cash equivalents,
end of period $ 8.6 $ 4.5 $ 8.6 $ 4.5
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Cash and cash equivalents
consists of:
Cash $ 4.2 $ 3.0 $ 4.2 $ 3.0
Cash equivalents 4.4 1.5 4.4 1.5
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Cash and cash equivalents,
end of period $ 8.6 $ 4.5 $ 8.6 $ 4.5
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Supplemental disclosure
of cash paid:
Interest $ 34.0 $ 34.7 $ 94.6 $ 93.0
Income and capital taxes 25.2 0.2 106.6 32.2
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See accompanying notes to the unaudited consolidated financial
statements.
Consolidated Statements of Changes in Shareholders' Equity (Unaudited)
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For the nine months Accu-
ended September 30, 2007 mulated
millions of dollars Other
Compre- Total
Contri- hensive AOCI and
Common buted Income Retained Retained
Shares Surplus ("AOCI") Earnings Earnings
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Balance, December 31,
2006 $1,055.2 $ 2.2 $ (100.2) $ 450.9 $ 350.7
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Implementation
adjustment (note 3) - - (5.3) (2.7) (8.0)
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Comprehensive Income:
Net earnings applicable
to common shares - - - 114.7 114.7
Net loss on derivatives
in a valid hedging
relationship - - (74.3) - (74.3)
Reclassification of
hedging losses
included in income - - 18.5 - 18.5
Reclassification of
hedging gains
included in inventory - - (1.0) - (1.0)
Unrealized loss on
translation of
self-sustaining
foreign operations - - (59.0) - (59.0)
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Total comprehensive
income - - (115.8) 114.7 (1.1)
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Dividends declared on
common shares - - - (74.5) (74.5)
Common shares issued
under purchase plans 7.2 - - - -
Senior management stock
options exercised 1.6 - - - -
Stock option expense - 0.5 - - -
Other share-based
compensation 0.2 - - - -
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Balance, September 30,
2007 $1,064.2 $ 2.7 $ (221.3) $ 488.4 $ 267.1
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For the nine months Total
ended September 30, 2006 Contri- AOCI and
millions of dollars Common buted Retained Retained
Shares Surplus AOCI Earnings Earnings
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Balance, December 31,
2005 $1,039.2 $ 1.8 $ (98.2) $ 423.4 $ 325.2
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Comprehensive Income:
Net earnings applicable
to common shares - - - 92.3 92.3
Unrealized loss on
translation of
self-sustaining
foreign operations - - (18.3) - (18.3)
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Total comprehensive
income - - (18.3) 92.3 74.0
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Dividends declared on
common shares - - - (73.6) (73.6)
Common shares issued
under purchase plans 6.4 - - - -
Senior management stock
options exercised 6.2 (0.4) - - -
Stock option expense - 0.6 - - -
Other share-based
compensation 0.2 - - - -
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Balance, September 30,
2006 $1,052.0 $ 2.0 $ (116.5) $ 442.1 $ 325.6
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See accompanying notes to the unaudited consolidated financial
statements.
Notes to the Interim Unaudited Consolidated Financial Statements
September 30, 2007
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,
2006.
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,
2006, 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
The Canadian Institute of Chartered Accountants ("CICA") has issued new
accounting standards 1530 Comprehensive Income, 3855 Financial Instruments -
Recognition and Measurement, and 3865 Hedges, which were applicable to the
Company effective January 1, 2007. In accordance with the new accounting
standards, the accounting policy changes were applied retroactively without
restatement of prior periods. The following provides more information on each
standard.
Comprehensive Income
As a result of the recently issued standard, a new item, accumulated other
comprehensive income ("AOCI"), is recognized in the shareholders' equity
section of the consolidated balance sheets. AOCI includes the unrealized
foreign exchange translation adjustments on the Company's self-sustaining
foreign operations, the effective portion of changes in fair value of
derivatives meeting the requirements for cash flow hedges, and unrealized
gains and losses on financial assets classified as available-for-sale.
Financial Instruments - Recognition and Measurement
According to the new standard, financial assets are now classified as
loans and receivables, held for trading, available for sale, or held to
maturity. Financial liabilities are classified as either held for trading, or
other than held for trading. The financial assets and liabilities are subject
to different methods of measurement and classification in the financial
statements as follows:
------------------------------------------------------------------------
Financial Instrument Measured at Classified in
------------------------------------------------------------------------
- Loans and receivables Amortized cost N/A
- Held to maturity financial
assets
- Other than held for trading
financial liabilities
------------------------------------------------------------------------
- Held for trading financial Fair value Net earnings unless
assets and liabilities deferral permitted under
regulatory accounting
------------------------------------------------------------------------
- Available for sale financial Fair value Other comprehensive
assets income
------------------------------------------------------------------------
In accordance with the new standard, transaction costs associated with the
issuance of long-term debt are included in long-term debt and amortized using
the effective interest method.
The Company has chosen January 1, 2003 as the transition date for embedded
derivatives and as a result, embedded derivatives existing prior to the
transition date are not reflected as separate assets and liabilities on the
balance sheet. An embedded derivative is a component of a contract with
characteristics similar to a derivative.
Hedges
The new standard outlines the criteria for applying hedge accounting to
cash flow hedges, fair value hedges, and hedging foreign currency fluctuations
on self-sustaining foreign operations.
Cash flow hedges are recognized on the balance sheet at fair value with
the effective portion of the hedging relationship recognized in other
comprehensive income. Any ineffective portion of the cash flow hedge is
recognized in net earnings. Amounts recognized in AOCI are reclassified to net
income in the same periods in which the hedged item is recognized in net
earnings.
Fair value hedges and the related hedged items are recognized on the
balance sheet at fair value with any changes in fair value recognized in net
income. To the extent the fair value hedge is effective, the changes in fair
value of the hedge and the hedged item will offset each other.
Hedges of self-sustaining foreign operations are recognized at fair value
with any changes in fair value recognized in other comprehensive income.
Accounting for the impact of rate-regulation:
In accordance with the new accounting standards as outlined above, Nova
Scotia Power determined that its contracts for the purchase or sale of natural
gas for its Tufts Cove generating station ("TUC") should be considered
derivative financial instruments and accordingly recognized at fair value as a
held for trading ("HFT") asset or liability as applicable. This reflects
NSPI's history of buying and reselling any natural gas not used in the
production of electricity at TUC.
Changes in the fair value of HFT assets and liabilities are recognized in
net earnings. In accordance with Nova Scotia Power's accounting policy
covering physical and financial contracts relating to fuel at TUC, NSPI has
deferred any changes in fair value to a regulatory asset or liability as
appropriate, which are reflected in deferred assets or credits. Upon
implementation of these accounting standards at January 1, 2007, the fair
value of these contracts was $171.9 million. Absent this accounting policy,
which has been approved by the UARB, retained earnings would have increased by
$171.9 million at January 1, 2007. As of September 30, 2007, the fair value of
the HFT asset and liability was $97.8 million. Absent this accounting policy,
the decrease of $74.1 million ($45.9 million after-tax) would have decreased
NSPI's year to date earnings.
Details of the amounts recognized upon implementation of the new
accounting standards, and the effect on the consolidated balance sheet as at
January 1, 2007 are summarized below:
Consolidated
Balance Sheet Balance Before Effect of Balance After
Selected Information Implementation Implementation Implementation
millions of dollars Adjustment Adjustment Adjustment
-------------------------------------------------------------------------
Current assets
Energy marketing assets $ 37.3 $(37.3) -
Derivatives held in
valid hedging
relationship - 13.9 $ 13.9
Held for trading
derivatives - 76.0 76.0
Energy marketing assets 2.0 (2.0) -
Derivatives in a valid
hedging relationship - 17.9 17.9
Held for trading derivatives - 136.4 136.4
Deferred charges 468.2 (11.3) 456.9
Investments 98.5 (98.5) -
Investments subject to
significant influence - 98.5 98.5
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$193.6
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Current liabilities
Current portion of
long-term debt $ 3.4 $ (0.2) $ 3.2
Energy marketing
liabilities 36.7 (36.7) -
Derivatives held in a
valid hedging
relationship - 26.6 26.6
Held for trading
derivatives - 39.7 39.7
Energy marketing
liabilities 1.4 (1.4) -
Derivatives in a valid
hedging relationship - 10.6 10.6
Held for trading derivatives - 2.6 2.6
Deferred credits 66.1 173.1 239.2
Long-term debt 1,657.4 (12.7) 1,644.7
Shareholders' equity
Foreign exchange
translation adjustment (100.2) 100.2 -
Accumulated other
comprehensive income - (105.5) (105.5)
Retained earnings 450.9 (2.7) 448.2
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$193.6
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The effect on the January 1, 2007 balances can be further explained as
follows:
Energy marketing assets and liabilities: The balances have been
reclassified to held for trading derivatives.
Derivatives in a valid hedging relationship: This new account represents
the fair value of Nova Scotia Power's hedges. These derivatives are all
designated as hedging future expected cash flows.
Held for trading derivatives: The new account includes the fair value of
certain of Nova Scotia Power's natural gas contracts, amounts previously
recognized as energy marketing assets and liabilities, and the fair value of
any derivatives that are not valid hedges.
Deferred charges: The adjustment represents the reclassification of
deferred financing costs which are now netted against the related debt,
partially offset by the regulatory asset resulting from the fair value
recognition of certain of Nova Scotia Power's natural gas contracts.
Investments: The adjustment represents the reclassification of equity
accounted investments to investments subject to significant influence.
Investments subject to significant influence: This new account represents
the reclassification of equity accounted investments from the investments
account as noted above.
Deferred credits: The adjustment represents the regulatory liability
resulting from the fair value recognition of certain of Nova Scotia Power's
natural gas contracts.
Long-term debt (including current portion): The adjustment represents the
netting of deferred financing costs against the related debt.
Foreign exchange translation adjustment: The adjustment represents the
reclassification of foreign exchange losses on self-sustaining foreign
operations to accumulated other comprehensive income.
Accumulated other comprehensive income: The adjustment represents the
effective portion of the fair value of Nova Scotia Power's hedges, and the
cumulative foreign exchange loss on self-sustaining foreign operations.
Retained earnings: The adjustment represents the fair value of Bear
Swamp's interim contract with the Long Island Power Authority ("LIPA").
As a result of implementing the accounting policy changes, earnings have
increased by $0.2 million ($0.1 million after-tax) in Q3 2007 and $2.7 million
($1.6 million after-tax) year to date 2007, which represents the change in
fair value of Bear Swamp's interim LIPA contract and the ineffective portion
of the Company's hedges.
The pre-tax effect of hedges recognized in earnings was a $9.0 million
loss in Q3 2007 (2006 - $9.5 million gain) and an $18.5 million loss year to
date 2007 (2006 - $30.0 million gain).
The fair value of derivatives in a valid hedging relationship and held for
trading derivatives are estimated by obtaining prevailing market rates from
investment dealers.
Future Accounting Policy Changes
The CICA has issued new accounting standards 1535 Capital Disclosures,
3031 Inventories, 3862 Financial Instruments - Disclosures, and 3863 Financial
Instruments - Presentation which are applicable to Emera's 2008 fiscal year.
The following provides more information on each new accounting standard.
Capital Disclosures: This new standard requires disclosure of the
Company's objectives, policies, and processes for managing capital;
quantitative data about what the Company regards as capital; whether the
Company has complied with any capital requirements; and, if the Company has
not complied, the consequences of such non-compliance. The new accounting
standard covers disclosure only and will have no effect on the financial
results of the Company.
Inventories: The new standard provides more guidance on the measurement
and disclosure requirements for inventories than the previous standard,
3030 Inventories. Specifically, the new standard requires that inventories be
measured at the lower of cost and net realizable value, and provides more
guidance on the determination of cost and its subsequent recognition as an
expense, including any write-down to net realizable value. The Company is
assessing the effect of the new standard and does not anticipate a material
effect on its results.
Financial Instruments - Disclosures, and Financial Instruments -
Presentation: These new standards replace accounting standard 3861 Financial
Instruments - Disclosure and Presentation. Presentation requirements have not
changed. Enhanced disclosure is required to assist users of the financial
statements in evaluating the significance of financial instruments on the
Company's financial position and performance, including qualitative and
quantitative information about the Company's exposure to risks arising from
financial instruments. The new accounting standards cover disclosure only and
will have no effect on the financial results of the Company.
4. Acquisition
On January 16, 2007 Emera acquired a 19% interest in St. Lucia Electricity
Services Limited ("Lucelec") for a purchase price of $25.7 million. Lucelec is
a vertically integrated electric utility with an exclusive license to
generate, transmit and distribute electricity on the island of St. Lucia to
2045. The utility has 77 MW of generating capacity and 800 kilometers of
electricity transmission and distribution assets. Lucelec is a cost of service
utility, with a minimum rate of return of 10% on a 50% equity basis.
The acquisition has been accounted for as an equity investment, and
accordingly, the investment was initially recorded at cost. Emera's pro-rata
share of the results since acquisition have been included in the investment
and consolidated statements of earnings. Any dividends received or receivable
reduces the investment. Lucelec is included in the segment "Other" in Note 5
Segment Information.
5. Segment Information
-------------------------------------------------------------------------
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Nova
Scotia Bangor
millions of dollars Power Hydro Other(x) Total
-------------------------------------------------------------------------
Three months ended
September 30, 2007:
Revenues from external
customers $ 252.4 $ 36.2 $ 21.7 $ 310.3
Net inter-segment
revenues (expenses) 14.4 (0.5) (13.9) -
Net earnings applicable
to common shares 25.0 9.1 6.8 40.9
Nine months ended
September 30, 2007:
Revenues from external
customers 826.9 105.9 62.8 995.6
Net inter-segment
revenues (expenses) 71.7 (1.5) (70.2) -
Net earnings applicable
to common shares 75.0 20.8 18.9 114.7
As at September 30, 2007
Total assets 3,218.2 608.5 348.5 4,175.2
-------------------------------------------------------------------------
Three months ended
September 30, 2006:
Revenues from external
customers $ 222.6 $ 34.2 $ 15.6 $ 272.4
Net inter-segment
revenues (expenses) 32.9 (0.8) (32.1) -
Net earnings applicable
to common shares 12.7 5.1 1.7 19.5
Nine months ended
September 30, 2006:
Revenues from external
customers 717.2 101.1 40.7 859.0
Net inter-segment
revenues (expenses) 122.0 (2.2) (119.8) -
Net earnings applicable
to common shares 74.4 11.5 6.4 92.3
As at September 30, 2006
Total assets 3,066.7 581.9 310.9 3,959.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x)Other consists of corporate activities and adjustments to reconcile
to consolidated balances.
6. Fuel for Generation and Purchased Power
Accounting for the impact of rate regulation:
In February 2007, the UARB approved an average increase in electricity
rates for NSPI of 3.8% effective April 1, 2007. The rate increase was part of
a settlement agreement between NSPI and key stakeholders. A provision of the
settlement agreement allows NSPI to defer, for future recovery in rates, up to
$8 million of fuel costs should natural gas margins be less than $47 million.
In Q2 2007 NSPI deferred $3.0 million. In the absence of the UARB's approval,
these costs would have been expensed as incurred and year-to-date 2007
earnings would be $3.0 million lower.
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 total
benefit cost, related to these plans, for the three month period ended
September 30, 2007 is $10.4 million (2006 - $10.7 million), and for the nine
month period ended September 30, 2007 is $31.4 million (2006 - $32.2 million).
8. Interest
Interest expense consists of the following:
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
million of dollars 2007 2006 2007 2006
-------------------------------------------------------------------------
Interest on long-term debt $ 24.7 $ 25.6 $ 76.6 $ 78.8
Interest on short-term debt 5.8 5.4 16.8 10.9
Amortization of debt
financing 0.5 0.5 1.4 1.5
Foreign exchange losses
(gains) 1.5 0.7 (0.5) 1.7
-------------------------------------------------------------------------
$ 32.5 $ 32.2 $ 94.3 $ 92.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
9. Income Taxes
NSPI prepared and filed with Canada Revenue Agency ("CRA") amended tax
returns for the years 2000 to 2004 inclusive. CRA reviewed and approved the
amended filings, which has resulted in accelerated deductibility of certain
capitalized expenses. NSPI intends to amend tax returns for 2005 and 2006
using the same methodology and will continue to use this methodology when
filing its future tax returns. As a result, NSPI has recorded an income tax
recovery of $25.4 million, of which $14.6 million has been recorded as a
reduction of deferred charges, specifically the regulatory asset related to
its pre-2003 income tax liability. The remaining $10.8 million has been
recorded as a reduction of current income tax expense. Refund interest has not
been estimated on the recovery as it is not reasonably determinable.
Accounting for the impact of rate regulation:
Absent NSPI's regulator approved taxes payable accounting policy, the
recovery would have no effect on the total current and future income tax
expense and net earnings for Q3 and year-to-date 2007 would be $10.8 million
lower.
10. Long-Term Debt
As of September 30, 2007, long-term debt includes $1.3 million
(December 31, 2006 - $3.8 million) in capital lease obligations.
11. Common Shares
As at September 30, 2007 there were 111.4 million (December 31, 2006 -
110.9 million) issued and outstanding common shares, 4.8 million (December 31,
2006 - 4.9 million) common shares reserved and available for issuance under
the senior management stock option plan, and 1.0 million (December 31, 2006 -
1.2 million) common shares reserved and available for issuance under the
employee common share purchase plan.
During the nine months ended September 30, 2007, the Company issued
0.4 million (2006 - 0.7 million) common shares. Common shares were issued
through the employee common share purchase plan, the senior management stock
option plan, and the dividend reinvestment plan.
Diluted weighted average number of common shares outstanding includes the
conversion of preferred shares of NSPI, restricted share units, and deferred
share units.
12. Comparative Information
Certain of the comparative figures have been reclassified to conform to
the consolidated financial statement presentation adopted for 2007.