Operating Cash Flow Doubles to $345.6 Million
HALIFAX, Feb. 16 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net earnings increased 4% to $125.8 million in 2006, compared to $121.2 million in 2005. Annual earnings per share were $1.14 compared to $1.11 in 2005. In 2005, a portion of income and other taxes, which would have otherwise been expensed, were deferred, pending regulatory approval of new rates. Without that deferral, 2005 comparative earnings would have been $16.7 million lower.
"We are encouraged by the progress we made in 2006," said Chris Huskilson, President and Chief Executive Officer of Emera Inc. "This year is also off to a positive start, with the settlement of NSPI's rate case, including an agreement in principal to establish a fuel adjustment mechanism for the utility. I am excited about our investment in St. Lucia, and look forward to exploring the Caribbean opportunity further in 2007."
Nova Scotia Power (NSPI), Emera's largest subsidiary, contributed $104.3 million to 2006 consolidated net earnings, compared to $91.2 million in 2005, and $107.3 million in 2004. The re-establishment of NSPI's earnings levels in 2006 is due to the combined effect of an electricity price increase early in the year; sales and production volume changes, reflecting the temporary shutdown of a large industrial customer and warmer weather; and increased proceeds from the resale of natural gas.
Consolidated net earnings for the three months ended December 31, 2006 were $33.5 million compared to $37.7 million for the fourth quarter of 2005. Quarterly earnings per share were $0.30 in 2006 compared to $0.34 in 2005.
NSPI contributed $29.9 million to consolidated net earnings in Q4 2006, compared to $34.0 million in Q4 2005. Earnings were lower quarter-over-quarter largely because 2005 amounts included a $15 million after-tax favourable adjustment to fuel expense for that year resulting from changes in NSPI's natural gas supply pricing, all of which was recorded in the fourth quarter. This was partially offset by higher revenues in Q4 2006 due to a price increase earlier in the year. Also, NSPI's fuel costs were lower quarter-over- quarter, primarily because warmer weather and slightly lower industrial sales enabled the utility to reduce its high marginal cost generation; and natural gas sales margin increased. NSPI's pension, depreciation and income tax costs increased slightly in Q4 2006 compared to the prior year, and the company also recorded higher regulatory amortization expense.
Bangor Hydro Electric (BHE), Emera's electricity transmission and distribution utility subsidiary in Maine, contributed $5.3 million to consolidated net earnings in Q4 2006, compared to $4.0 million in Q4 2005; and $16.8 million for the year ended December 31, 2006 compared to $14.9 million in 2005. Lower operating expenses reflecting the capitalization of costs associated with the Northeast Reliability Interconnect transmission project more than offset the effects of a stronger Canadian dollar.
Emera's Other operations contributed $4.7 million to consolidated net earnings compared to $15.1 million in 2005. 2005 amounts include $5.2 million of foreign exchange gains which did not recur in 2006. Finally, softer market conditions reduced natural gas marketing opportunities and also decreased electricity margins at Bear Swamp. For the three months ended December 31, 2006, Other operations incurred a loss before interest and taxes of $1.7 million in Q4 2006, compared to a loss of $0.3 million in Q4 2005.
Consolidated cash provided by operating activities improved significantly, to $345.6 million for the year ended December 31, 2006, compared to $164.3 million in 2005, reflecting the improvement in earnings and in working capital. Q4 2006 cash provided by operating activities was $106.7 million compared to cash used in operating activities of $36.3 million in Q4 2005 for the same reasons.
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).
Teleconference Call
Emera is holding a teleconference today at 4:00 pm Atlantic (3:00 pm Toronto/Montreal/New York; 2:00 pm Winnipeg; noon Vancouver) to discuss the Q4, 2006 financial results. Analysts and other interested parties wanting to participate in the call should dial 1-888-575-8232 (in Toronto 416-406-6419) at least 10 minutes prior to the start of the call. No pass code is required. The teleconference will be recorded. If you are unable to join the teleconference live, you can dial for playback toll-free at 1-800-408-3053 (in Toronto 416-695-5800), access code 3212600(number sign) (available until midnight, Friday, March 2, 2007). The teleconference will also be web cast live at www.emera.com and available for playback for one year.
About Emera
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 and provides related services. Visit Emera on the web at www.emera.com.
Management's Discussion & Analysis
As at February 16, 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 fourth quarter of 2006 relative to 2005, and the full year 2006 relative to 2005 and to 2004; and its financial position at December 31, 2006 relative to 2005. 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. annual audited consolidated financial statements and supporting notes. 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.
CONSOLIDATED FINANCIAL HIGHLIGHTS
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005 2004
-------------------------------------------------------------------------
Revenues $ 307.0 $ 297.1 $1,166.0 $1,168.0 $1,134.2
Net earnings from
continuing operations 33.5 37.7 125.8 122.1 127.6
Consolidated net
earnings 33.5 37.7 125.8 121.2 129.8
Earnings per common
share - basic
Continued operations 0.30 0.34 1.14 1.12 1.18
Total 0.30 0.34 1.14 1.11 1.20
Earnings per common
share - fully diluted
Continued operations 0.30 0.34 1.12 1.10 1.14
Total 0.30 0.34 1.12 1.09 1.16
Cash dividends declared
per share 0.2225 0.2225 0.89 0.89 0.88
-------------------------------------------------------------------------
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As at December 31
2006 2005 2004
-------------------------------------------------------------------------
Total assets $4,059.8 $3,998.6 $3,949.2
Total long-term liabilities 2,149.9 2,126.0 2,118.8
-------------------------------------------------------------------------
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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
comprise approximately 95% of Emera's consolidated revenues:
- Nova Scotia Power Inc. ("NSPI") is an electricity generation,
transmission and distribution company, providing service to the vast
majority of the province of Nova Scotia. NSPI has $3 billion in assets,
and 470,000 customers. NSPI is a cost of service utility. As such,
regulated electricity rates are set to enable the company to recover
all prudently incurred costs, with an opportunity to earn a prescribed
return on equity. The company is regulated by the Nova Scotia Utility
and Review Board ("UARB").
- Bangor Hydro-Electric Company ("BHE") is an electricity transmission
and distribution company with $640 million of assets serving 115,000
customers in eastern Maine. BHE's transmission operations are regulated
by the Federal Energy Regulatory Commission ("FERC"), and its
distribution operations are regulated by the Maine Public Utilities
Commission ("MPUC"). BHE is a cost of service utility, with an
alternate rate plan ("ARP") for its distribution operations.
The success of Emera's electric utilities is integral to the creation of
shareholder value, providing substantial earnings and cash flow to fund
dividends and reinvestment. The essential nature of the services provided, the
monopoly positions, and the regulated market structures means that NSPI and
BHE can generally be expected to produce stable earnings streams within
regulated ranges. Nova Scotia and Maine are mature electricity markets, with
annual demand growth of approximately 2%. Accordingly, Emera must look beyond
its existing regulated electricity business to supplement organic growth.
Emera's objective is to deliver annual consolidated earnings growth of 4%-
6%, and build and diversify its earnings base such that eventually 35% of
consolidated net earnings are derived from investments other than Nova Scotia
Power. Emera's plan for growth leverages its core strength in the electricity
business. Emera will pursue both acquisitions and greenfield development
opportunities in regulated electricity transmission and distribution and low
risk generation. Emera will also capitalize on opportunities in related energy
infrastructure businesses appropriate to its risk profile, where its
development, commercial and operational skills are needed.
Recent investments include:
- Bear Swamp, a 600 megawatt ("MW") pumped storage hydro-electric
generating facility in northern Massachusetts, acquired in a joint
venture with Brookfield Power in 2005;
- Brunswick Pipeline, a proposed $350 million greenfield pipeline project
under development that will deliver natural gas from the planned
Canaport(TM) Liquefied Natural Gas ("LNG") import terminal near Saint
John, New Brunswick to markets in Canada and the US northeast. The
145 kilometer Brunswick Pipeline will travel through southwest New
Brunswick and connect with the Maritimes and Northeast Pipeline
("M&NP") at the Canada/US border near Baileyville, Maine. Emera has
been an investor in M&NP since its inception in 1999.
Canaport(TM) LNG is a partnership of Repsol YPF, S.A. ("Repsol") and
Irving Oil Limited. Emera has negotiated a 25 year send or pay toll
agreement with Repsol to transport natural gas through the Brunswick
Pipeline. Emera has also negotiated agreements with its M&NP partner,
Spectra Energy Corp, formerly Duke Energy, ("Spectra") an affiliate of
which will assist Emera in the Brunswick Pipeline permitting process,
and construct and operate the pipeline on Emera's behalf.
Emera expects to finance the investment with internally generated cash
flow and debt. The investment is forecast to provide a return on
project equity of 11% - 14%.
The project requires National Energy Board ("NEB") approval. NEB
hearings were completed in November 2006, with a decision expected in
Q2 2007. Assuming approval is granted, the pipeline is expected to be
in service by the end of 2008.
Emera's net cash requirements related to Brunswick Pipeline are
expected to be $65.0 million for 2007.
- St. Lucia Electricity Services Limited ("Lucelec"), 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 US $22 million in January 2007.
Lucelec has an exclusive license to generate, transmit and distribute
electricity on the island to 2045. The utility has 66 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 to $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.
Consolidated Net Earnings History
(millions of dollars)
2006 2005 2004 2003 2002 2001
$ 125.8 $ 121.2 $ 129.8 $ 129.2 $ 83.6 $ 114.2
Earnings per Share History
(dollars)
2006 2005 2004 2003 2002 2001
$ 1.14 $ 1.11 $ 1.20 $ 1.20 $ 0.85 $ 1.20
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 the Maritimes &
Northeast Pipeline, Emera Energy Services, Bear Swamp, and corporate
activities are grouped and discussed as "Other". Significant changes in the
consolidated balance sheets, outstanding share data, liquidity and capital
resources, financial and commodity instruments, transactions with related
parties, disclosure and internal controls, critical accounting estimates,
changes in accounting policies, dividend policy and payout ratios, business
risks and enterprise risk management, and selected quarterly trend information
are presented on a consolidated basis.
EMERA CONSOLIDATED
Summary Consolidated
Income Statement
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005 2004
-------------------------------------------------------------------------
Electric revenue $ 301.6 $ 287.3 $1,132.0 $1,125.9 $1,095.7
Other 5.4 9.8 34.0 42.1 38.5
-------------------------------------------------------------------------
307.0 297.1 1,166.0 1,168.0 1,134.2
Fuel for generation and
purchased power 102.3 96.7 347.7 432.0 350.0
Operating, maintenance
and general 65.0 61.9 255.6 248.2 245.2
Provincial, state, and
municipal taxes 11.7 11.8 48.0 48.4 46.3
Provincial tax deferral - 0.4 - (4.5) -
Depreciation 36.9 34.2 145.2 136.1 131.2
Regulatory amortization 6.2 2.9 22.8 19.4 26.1
Other (3.3) (2.7) (10.7) (10.9) (10.2)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 88.2 91.9 357.4 299.3 345.6
Interest 34.2 38.4 127.1 117.4 126.8
Amortization of
defeasance costs 3.2 3.3 12.7 13.2 15.1
Other income (8.9) (8.0) (8.9) (8.0) -
-------------------------------------------------------------------------
Earnings before income
taxes 59.7 58.2 226.5 176.7 203.7
Income taxes 22.9 19.0 87.4 53.5 62.7
Income taxes deferral - (1.8) - (12.2) -
-------------------------------------------------------------------------
Net earnings before non-
controlling interest 36.8 41.0 139.1 135.4 141.0
Non-controlling interest 3.3 3.3 13.3 13.3 13.4
-------------------------------------------------------------------------
Net earnings from
continuing operations 33.5 37.7 125.8 122.1 127.6
(Loss) earnings from
discontinued operations,
net of tax - - - (0.9) 2.2
-------------------------------------------------------------------------
Net earnings applicable
to common shares $ 33.5 $ 37.7 $ 125.8 $ 121.2 $ 129.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic
Continuing operations $ 0.30 $ 0.34 $ 1.14 $ 1.12 $1.18
Discontinued
operations - - - (0.01) 0.02
-------------------------------------------------------------------------
$ 0.30 $ 0.34 $ 1.14 $ 1.11 $ 1.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - diluted
Continuing operations $0.30 $0.34 $1.12 $ 1.10 $1.14
Discontinued
operations - - - (0.01) 0.02
-------------------------------------------------------------------------
$0.30 $0.34 $1.12 $ 1.09 $ 1.16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Unit Contributions
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005 2004
-------------------------------------------------------------------------
Nova Scotia Power $ 29.9 $ 34.0 $ 104.3 $ 91.2 $ 107.3
Bangor Hydro-Electric 5.3 4.0 16.8 14.9 18.5
Other, including
corporate costs (1.7) (0.3) 4.7 15.1 4.0
-------------------------------------------------------------------------
Consolidated net
earnings $ 33.5 $ 37.7 $ 125.8 $ 121.2 $ 129.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of 2006
Emera Inc.'s consolidated earnings decreased $4.2 million to $33.5 million
in Q4 2006 compared to $37.7 million for the same period in 2005. Emera's
annual consolidated earnings were $125.8 million in 2006 compared to $121.2
million in 2005 and $129.8 million in 2004. Highlights of the changes are
summarized in the following table:
Three
months Year
ended ended
December December
millions of dollars 31 31
-------------------------------------------------------------------------
Consolidated net earnings - 2004 $ 129.8
Increased electric revenue in NSPI due to an
electricity price increase, partially offset by a
36 GWh decrease in sales volume 28.1
Increased fuel expense in NSPI due to higher
commodity prices, and changes in generation mix
partially offset by increased hydro production and
natural gas resale margin (70.7)
Increased operating expenses in NSPI reflecting
increased planned plant maintenance, storm-related
costs, and regulatory costs (11.3)
Net payment from a gas supplier in NSPI 8.0
Decreased income taxes in NSPI resulting from
lower earnings 13.7
Deferral of Q1 2005 taxes in NSPI 16.7
Addition of Bear Swamp hydro-electric facility
earnings before interest & taxes 4.2
Foreign exchange gains in Other reflecting an
adjustment to refine prior years' foreign exchange 5.2
All other (2.5)
-------------------------------------------------------------------------
Consolidated net earnings - 2005 $ 37.7 $ 121.2
Increased electric revenue in NSPI due to
electricity price increases and increased export
sales partially offset by reduced industrial sales
volume and warmer weather year over year 15.0 12.9
Decreased fuel expense year over year in NSPI due to
reduced load and increased natural gas sales margin
partially offset by higher commodity prices and
increased export sales; quarter over quarter
includes a favourable adjustment in Q4 2005 to
reflect finalization of pricing terms of NSPI's
natural gas supply contract (8.2) 81.0
Increased operating expenses in NSPI mainly due to
pension costs (2.7) (13.7)
Increased depreciation and regulatory amortization
in NSPI (4.4) (10.7)
Increased interest expense in NSPI due to higher
long-term debt balances and foreign exchange losses
on USD contracts (1.6) (7.5)
Insurance proceeds received for a supply
interruption claim in NSPI 8.9 8.9
Net payment from a gas supplier in NSPI in 2005 (8.0) (8.0)
Increased taxes in NSPI primarily due to higher
taxable income (2.0) (34.8)
Deferral of Q1 2005 taxes in NSPI (1.4) (16.7)
Increased overheads capitalized in BHE primarily as
a result of capital expenditures on the Northeast
Reliability Interconnect transmission project 3.2 6.3
Decreased earnings before interest and taxes in Emera
Energy Services and Bear Swamp (1.8) (6.0)
Foreign exchange gains in Other recognized in 2005
reflecting an adjustment to refine prior years'
foreign exchange - (5.2)
All other (1.2) (1.9)
-------------------------------------------------------------------------
Consolidated net earnings - 2006 $ 33.5 $ 125.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q4 basic earnings per share were $0.30 in 2006 compared to $0.34 in 2005;
and $1.14 for the full year 2006 compared to $1.11 in 2005 and $1.20 in 2004.
SIGNIFICANT ITEMS
2006
In late 2005 a number of Nova Scotia Power's petroleum coke suppliers were
unable to supply fuel due to hurricanes in the Gulf of Mexico which seriously
affected their operations. As a result, Nova Scotia Power incurred additional
costs for replacement fuel and other expenses, which were included in Q4 2005
fuel expense. NSPI filed a claim with its insurers to recover applicable
costs. In Q4 2006, Nova Scotia Power received $8.9 million ($5.5 million
after-tax) in settlement of this claim.
2005
Natural gas supply contract
In Q4 2005, Nova Scotia Power reached an agreement with its supplier on
pricing for natural gas under an existing long-term natural gas purchase
agreement. The contract was subject to a price re-determination as of November
1, 2004. Throughout most of 2005, while the new pricing was under discussion,
NSPI recorded its gas purchases at its best estimate of the new contract
price. The pricing ultimately agreed to was more favourable than NSPI's
estimate. This resulted in a $23.8 million ($14.7 million after-tax)
adjustment to fuel expense for 2005, all of which was recorded in Q4 2005. In
addition, in a separate agreement, NSPI was provided a net payment of
$8.0 million ($5.0 million after-tax) by its gas supplier, which was recorded
as other income in Q4 2005.
Deferral of Q1 Income and Capital Taxes
The UARB agreed to allow Nova Scotia Power to defer taxes not reflected in
rates for the period January 1, 2005 until April 1, 2005, the date when new
rates became effective. In 2005, NSPI deferred $16.7 million, consisting of
$4.5 million of provincial and federal grants and $12.2 million in income
taxes reflecting increases in these taxes since rates had last been set in
2002.
2004
There were no significant items in 2004.
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.
The company owns 2,293 megawatts ("MW") of generating capacity. Approximately
55% is coal-fired; oil and natural gas together comprise another 30% of
capacity; and hydro and wind production provide the remainder. NSPI has 86 MW
of renewable energy, substantially wind energy, under contract with
independent power producers. 80 MW are in service and the remainder is
expected to be in operation in the next 12 months. NSPI also owns
approximately 5,000 kilometers of transmission facilities, and
25,000 kilometers of distribution facilities. The company has a workforce of
approximately 1,700 people.
NSPI is a public utility as defined in the Public Utilities Act (Nova
Scotia) and is subject to regulation under the Act by the UARB. The Act gives
the UARB supervisory powers over NSPI's operations and expenditures.
Electricity rates for NSPI's customers are also subject to UARB approval. The
company is not subject to an annual rate review process, but rather
participates in hearings from time to time at the company's or the regulator's
request.
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 appropriate return to investors. NSPI's allowed
return on equity range is 9.3% to 9.8%, on a maximum allowed common equity
component of 40% of total capitalization. Rates were last set at a 9.55%
return on equity, with a common equity component of 37.5%.
2007 Rate Decision
In October 2006, NSPI filed an application for an average rate increase of
7.5%. The proposed increase was to cover increased fuel costs and costs
previously approved but deferred for future recovery by the UARB.
In January 2007 NSPI and most parties to the application presented a
settlement agreement to the UARB, which provided for an average increase in
electricity rates of 3.8% effective April 1, 2007. The decrease in the revenue
requirement compared to the original application primarily reflects a
reduction in the company's forecast fuel costs and the postponement of the
phase-in of higher depreciation rates. Other key elements of the original
application were unchanged in the settlement, including rate base, return on
equity (maintained at 9.3% - 9.8%), operating, maintenance and general
expenditures, and recovery of previously deferred and paid taxes.
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.
The settlement was approved by the regulator on February 5, 2007. Hearings
on the implementation of a FAM are expected in mid-2007.
2006 Rate Decision
The Nova Scotia Utility and Review Board granted NSPI an average rate
increase of approximately 8.7% effective March 10, 2006. The UARB noted
improvements NSPI had made in fuel procurement, but determined that a previous
finding related to 2002 and 2003 fuel procurement carried over into 2006,
resulting in a $15.7 million disallowance for 2006. The UARB noted that this
would be the final disallowance related to this issue.
2005 Rate Decision
On March 31, 2005, the UARB granted NSPI an average rate increase of
approximately 5.3%, effective April 1, 2005. In the 2005 decision, the UARB
expressed dissatisfaction with certain past fuel procurement practices,
resulting in a disallowance of $18 million of NSPI's forecasted 2005 fuel
costs.
Review of 2006
NSPI Net Earnings
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005 2004
-------------------------------------------------------------------------
Electric revenue $ 257.9 $ 243.0 $ 967.9 $ 955.0 $ 926.9
-------------------------------------------------------------------------
Fuel for generation
and purchased power 87.7 79.5 292.8 373.8 303.1
Operating, maintenance
and general 51.5 48.8 202.5 188.8 177.5
Provincial grants and
taxes 10.1 10.2 40.3 40.4 39.5
Provincial grants and
taxes deferral - 0.4 - (4.5) -
Depreciation 32.1 30.1 127.8 119.5 116.0
Regulatory amortization 3.9 1.5 8.6 6.2 6.2
Other (2.9) (2.6) (11.2) (10.1) (10.4)
-------------------------------------------------------------------------
Earnings before
interest and income
taxes 75.5 75.1 307.1 240.9 295.0
Interest 27.4 25.8 105.4 97.9 100.1
Amortization of
defeasance costs 3.2 3.3 12.7 13.2 15.1
Other income (8.9) (8.0) (8.9) (8.0) -
-------------------------------------------------------------------------
Earnings before income
taxes 53.8 54.0 197.9 137.8 179.8
Income taxes 20.5 18.5 80.3 45.5 59.2
Income taxes deferral - (1.8) - (12.2) -
-------------------------------------------------------------------------
Earnings before
preferred dividends 33.3 37.3 117.6 104.5 120.6
Preferred dividends 3.4 3.3 13.3 13.3 13.3
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings $ 29.9 $ 34.0 $ 104.3 $ 91.2 $ 107.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share $ 0.27 $ 0.30 $ 0.94 $ 0.83 $ 0.99
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's contribution to consolidated net earnings decreased $4.1 million to
$29.9 million in Q4 2006, compared to $34.0 million in Q4 2005. Annual
contribution to consolidated net earnings increased $13.1 million to
$104.3 million in 2006 compared to $91.2 million in 2005, and was
$107.3 million in 2004. Highlights of the earnings changes are summarized in
the following table:
Three
months Year
ended ended
December December
millions of dollars 31 31
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $ 107.3
Increased electric revenue due to an electricity
price increase, partially offset by a 36 GWh
decrease in sales volume 28.1
Increased fuel expense due to higher commodity
prices, and changes in generation mix partially
offset by increased hydro production and natural
gas resale margin (70.7)
Increased operating expenses reflecting increased
planned plant maintenance, storm-related costs, and
regulatory costs (11.3)
Net payment from a gas supplier 8.0
Decreased income taxes resulting from lower earnings 13.7
Deferral of Q1 2005 taxes 16.7
All other (0.6)
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $ 34.0 $ 91.2
Increased electric revenue due to electricity price
increases and increased export sales 15.3 87.1
Decreased electric revenue due to reduced industrial
sales volume and warmer weather year over year (0.3) (74.2)
Decreased fuel expense year over year due to reduced
load and increased natural gas sales margin
partially offset by higher commodity prices and
increased export sales; quarter over quarter
includes a favourable adjustment in Q4 2005 to
reflect finalization of pricing terms of NSPI's
natural gas supply contract (8.2) 81.0
Increased operating expenses mainly due to
pension costs (2.7) (13.7)
Increased depreciation and regulatory amortization (4.4) (10.7)
Increased interest expense due to higher long-term
debt balances and foreign exchange losses on
USD contracts (1.6) (7.5)
Insurance proceeds received for a supply
interruption claim 8.9 8.9
Net payment from a gas supplier in 2005 (8.0) (8.0)
Increased taxes primarily due to higher
taxable income (2.0) (34.8)
Deferral of Q1 2005 taxes (1.4) (16.7)
All other 0.3 1.7
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2006 $ 29.9 $ 104.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q4 Electric Sales Volume Q4 Electric Sales Revenues
Gigawatt hours ("GWh") millions of dollars
------------------------------------ ------------------------------------
2006 2005 2004 2006 2005 2004
------------------------------------ ------------------------------------
Residential 1,016 999 1,052 Residential $115.5 $104.2 $103.4
Commercial 742 728 754 Commercial 72.0 65.3 66.3
Industrial 925 1,020 1,068 Industrial 58.5 58.6 55.3
Other 119 144 153 Other 11.9 14.9 12.8
------------------------------------ ------------------------------------
Total 2,802 2,891 3,027 Total $257.9 $243.0 $237.8
------------------------------------ ------------------------------------
------------------------------------ ------------------------------------
Year-to-Date ("YTD") Electric YTD Electric Sales Revenues
Sales Volume
GWh millions of dollars
------------------------------------ ------------------------------------
2006 2005 2004 2006 2005 2004
------------------------------------ ------------------------------------
Residential 3,927 4,000 4,039 Residential $439.9 $411.4 $402.9
Commercial 3,023 3,004 2,965 Commercial 285.2 263.6 258.3
Industrial 2,874 4,197 4,196 Industrial 184.8 235.1 222.5
Other 684 436 473 Other 58.0 44.9 43.2
------------------------------------ ------------------------------------
Total 10,508 11,637 11,673 Total $967.9 $955.0 $926.9
------------------------------------ ------------------------------------
------------------------------------ ------------------------------------
Q4 Average Revenue /
Megawatt hour ("MWh")
------------------------------------
2006 2005 2004
------------------------------------
Dollars
per MWh $ 92 $ 84 $ 79
------------------------------------
------------------------------------
YTD Average Revenue / MWh
------------------------------------
2006 2005 2004
------------------------------------
Dollars
per MWh $ 92 $ 82 $ 79
------------------------------------
------------------------------------
Electric sales volume is primarily driven by general economic conditions,
population and weather. Electricity pricing in Nova Scotia is regulated and
therefore only changes when new regulatory decisions are implemented. The
exceptions are annually adjusted rates, subscribed to by certain larger
industrial customers, and export sales which in recent years comprised less
than 2% of NSPI sales volume and are priced at market. Residential and
commercial electricity sales are seasonal, with Q1 and Q4 the strongest
periods, reflecting colder weather, and fewer daylight hours in the winter
season.
NSPI's residential load generally comprises individual homes, apartments
and condominiums. Commercial customers include everything from small retail
operations to large office and commercial complexes, and the province's
universities and hospitals. Industrial customers include manufacturing
facilities and other large volume operations. Other consists of export sales,
sales to municipal electric utilities and revenues from street lighting.
Electric revenues increased by $14.9 million to $257.9 million in Q4 2006
from $243.0 million for the same period in 2005. Revenue increases are
substantially due to the 8.7% rate increase effective March 10, 2006.
For the year ended December 31, 2006, electric revenues increased
$12.9 million to $967.9 million in comparison to $955.0 million in 2005. The
impact of the rate increase noted above and increased export sales was
partially offset by the temporary shut-down of the large industrial customer
for much of 2006, and warmer weather year over year.
For the year ended December 31, 2005, electric revenues increased
$28.1 million, to $955.0 million from $926.9 million in 2004 substantially due
to a 5.3% rate increase effective April 1, 2005. 2005 sales volumes were
slightly lower than 2004, reflecting warmer weather and the temporary shut-
down of the large customer for a portion of December 2005.
The increase in average revenue per MWh in the quarter and year to date
reflects the rate increases noted above, and a change in sales mix,
specifically a reduction in industrial sales.
Fuel for Generation and Purchased Power
Capacity
To ensure reliability of service, NSPI maintains a generating capacity
greater than firm peak demand. The total company-owned generation capacity is
2,293 MW, which is supplemented by 80 MW in service contracted with
independent power producers. NSPI meets the planning criteria for reserve
capacity established by the Maritime Control Area, and the Northeast Power
Coordinating Council.
Management of capacity/capacity utilization is a critical element of
operating efficiency. The provision of sufficient generating capacity to meet
peak demand inevitably results in excess capacity in non-peak periods. NSPI's
daily load is highest in the early evening; its seasonal load is highest
through the winter months. Summer cooling load is not a significant factor.
Maximizing capacity utilization has a positive effect on earnings, and helps
defer significant investment in additional generation capacity. Maximizing
capacity utilization primarily depends on:
- Ensuring generating plants are consistently available to service
demand - NSPI conducts ongoing planned maintenance programs, and has
sustained high availability over the past several years. NSPI continues
to maintain unplanned outage rates below 3%.
- Moving demand from peak to non-peak periods - NSPI encourages customers
to move some electricity demand from high cost to lower cost periods by
offering customers various pricing alternatives. NSPI controls over
300 MW of interruptible electric load; over 250 MW is supplied under
real time or time of day rates.
- Export sales - Increasing export sales when margins are satisfactory
allows excess capacity to be sold when not required in the province.
NSPI operates a 24-hour marketing desk to optimize commercial
opportunities.
NSPI Thermal Capacity Utilization
2006 2005 2004 2003 2002 2001
71% 78% 82% 78% 77% 77%
NSPI's generating capacity utilization was 71% in 2006 compared to 78% in
2005. The Net System Requirement was reduced in 2006 due to NSPI's largest
customer not operating for most of the year, and warmer weather year-over-
year reducing the home heating load.
NSPI Generating Capacity Availability
2006 2005 2004 2003 2002 2001
90% 90% 92% 91% 91% 91%
NSPI facilities continue to rank among the best in Canada on capacity
related performance indicators. In the most recent Canadian Electrical
Association rankings, NSPI units hold five of the top ten positions in the
country. The company's Trenton 6 unit ranked first.
Fuel Expense
Q4 Production Volume YTD Production Volume
GWh GWh
------------------------------------ ------------------------------------
2006 2005 2004 2006 2005 2004
------------------------------------ ------------------------------------
Coal & Coal &
petcoke 2,368 2,280 2,471 petcoke 9,128 9,116 9,490
Natural gas 128 32 26 Natural gas 390 194 97
Oil 174 442 433 Oil 431 1,581 1,698
Renewable 233 308 265 Renewable 998 1,063 889
Purchased Purchased
power 180 126 91 power 405 529 391
------------------------------------ ------------------------------------
Total 3,083 3,188 3,286 Total 11,352 12,483 12,565
------------------------------------ ------------------------------------
------------------------------------ ------------------------------------
Purchased power includes 33 GWh of Purchased power includes 109 GWh of
wind power in 2006 (2005 - 29 GWh). wind power in 2006 (2005 - 83 GWh).
Q4 Average Unit Fuel Costs
------------------------------------
2006 2005 2004
------------------------------------
Dollars per
MWh $ 28 $ 25 $ 26
------------------------------------
------------------------------------
YTD Average Unit Fuel Costs
------------------------------------
2006 2005 2004
------------------------------------
Dollars per
MWh $ 26 $ 30 $ 24
------------------------------------
------------------------------------
Coal is NSPI's dominant fuel source, supplying approximately 58% of the
company's annual generation. Petroleum coke ("petcoke") fuels approximately
23% of generation. These solid fuels have the lowest per unit fuel cost, after
hydro and wind production, which have no fuel cost component. Oil and natural
gas are next, depending on the relative pricing of each. Purchased power is
generally the most expensive option. Economic dispatch of the generating fleet
brings the lowest cost options on stream first, with the result that the
incremental cost of production increases as sales volume increases.
Accordingly, in 2006, the reduction in industrial load resulted in a decrease
in oil fired production.
The Q4 average unit fuel costs are higher in 2006 due to a favourable
adjustment in Q4 2005 to reflect finalization of pricing terms of the natural
gas supply contract. The year to date average unit fuel costs have decreased
in 2006 mainly due to higher natural gas margins, and NSPI's reduced use of
higher priced fuels because of reduced load.
A substantial amount of NSPI's fuel supply comes from international
suppliers, and is subject to commodity price and foreign exchange risk. The
company manages exposure to commodity price risk utilizing a portfolio
strategy, combining physical fixed-price fuel contracts and financial
instruments providing fixed or maximum prices. Foreign exchange risk is
managed through forward and option contracts. Further details on the company's
fuel cost risk management strategies are included in the Business Risk and
Enterprise Risk Management section.
For the three months ended December 31, 2006, fuel for generation and
purchased power increased $8.2 million to $87.7 million, compared to
$79.5 million in Q4 2005. For the year ended December 31, 2006, fuel for
generation and purchased power decreased $81.0 million to $292.8 million
compared to $373.8 million in 2005 and $303.1 million in 2004. Highlights of
the changes are summarized in the following table:
Three months Year
ended ended
December December
millions of dollars 31 31
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2004 $ 303.1
Commodity pricing increase 91.1
Higher net proceeds from resale of natural gas (13.6)
Changes in generation mix 12.2
Increase in hydro production volumes (11.7)
All other (7.3)
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2005 $ 79.5 $ 373.8
Decreased load due to the temporary shutdown of
a large industrial customer and warmer weather (14.5) (79.6)
Increased net proceeds from the resale of natural gas (11.2) (23.2)
Commodity pricing increase 5.7 18.8
Decreased hydro production 3.7 2.2
Increased fuel expense due to favourable adjustment
in Q4 2005 to reflect finalization of pricing terms
of natural gas supply contract 23.8 -
All other 0.7 0.8
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2006 $ 87.7 $ 292.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In Q4 2005, Nova Scotia Power reached an agreement with its supplier on
pricing for natural gas under an existing long-term natural gas purchase
agreement. The contract was subject to a price re-determination as of November
1, 2004. Throughout most of 2005, while the new pricing was under discussion,
NSPI recorded its gas purchases at its best estimate of the new contract
price. The pricing ultimately agreed to was more favourable than NSPI's
estimate. This resulted in a $23.8 million ($14.7 million after-tax)
adjustment to fuel expense for 2005, all of which was recorded in Q4 2005. In
addition, in a separate agreement, NSPI was provided a net payment of
$8.0 million ($5.0 million after-tax) by its gas supplier, which was recorded
as other income in Q4 2005.
Operating, Maintenance and General Expenses
NSPI's operating, maintenance and general expenses increased $2.7 million,
to $51.5 million in Q4 2006 compared to $48.8 million in Q4 2005, primarily
due to higher pension costs. For the year ended December 31, 2006, NSPI's
operating, maintenance and general expenses increased $13.7 million, to $202.5
million compared to $188.8 million in 2005 primarily for the same reason.
Operating, maintenance and general expenses increased $11.3 million, to
$188.8 million in 2005 from $177.5 million in 2004, due to increased planned
plant maintenance, storm-related costs and regulatory costs.
Provincial Grants and Taxes
NSPI pays annual grants to the Province of Nova Scotia, in lieu of
municipal taxation other than deed transfer tax.
In Q1 2005, the UARB agreed to allow NSPI to defer taxes not included in
rates for the period from January 1, 2005 until April 1, 2005, the date when
new rates became effective. In its February 5, 2007 decision, the UARB
approved amortization of the deferred amount over an eight year period,
beginning April 1, 2007.
Depreciation
NSPI's depreciation expense increased $2.0 million in Q4 2006, to
$32.1 million compared to $30.1 million in Q4 2005, primarily due to the
scheduled phase-in of increased depreciation rates as approved by the UARB.
For the year ended December 31, 2006 depreciation expense increased
$8.3 million, to $127.8 million compared to $119.5 million in 2005, for the
reason noted above. The 2005 amount is $3.5 million higher than 2004,
reflecting increased plant-in-service.
In its February 5, 2007 decision, the UARB postponed the scheduled
year-three phase-in of increased depreciation rates until the next rate
application.
Regulatory Amortization
The Glace Bay generating station has been returned to an industrial
greenfield site, and is being amortized at a minimum annual rate of
$6.2 million. In 2006 NSPI amortized $8.6 million (2005 - $6.2 million). The
amount remaining to be written off is $5.1 million.
Interest
Interest expense increased $1.6 million, to $27.4 million in Q4 2006
compared to $25.8 million in Q4 2005, primarily due to a gain recognized in
2005 on an interest rate derivative.
For the year ended December 31, 2006, interest expense increased
$7.5 million, to $105.4 million compared to $97.9 million in 2005 due to the
issuance in November 2005 of a $150 million 5.67% medium-term note which
partially refinanced short-term debt, and foreign exchange losses.
For the year ended December 31, 2005, interest expense decreased
$2.2 million, to $97.9 million from $100.1 million for 2004 largely due to the
refinancing in May 2005 of a $100 million 8.38% medium-term note with a
$100 million 4.22% medium-term note.
The company manages exposure to interest rate risk through a combination
of fixed and floating borrowing, and hedging. Interest rate caps are the
principal instrument used to hedge interest rate risk.
Other Income
In Q4 2006, Nova Scotia Power received an $8.9 million insurance
settlement on a petcoke supply interruption claim.
In Q4 2005, Nova Scotia Power received a net payment of $8.0 million from
a natural gas supplier as part of renegotiation of contractual matters.
Income Taxes
In accordance with ratemaking regulations established by the UARB, NSPI
uses the taxes-payable method of accounting for income taxes.
NSPI is subject to provincial capital tax (0.263%), corporate income tax
(38.12%) and Part VI.1 tax relating to preferred dividends (40%).
In addition to the deferral of provincial grants and taxes referred to
above, in Q1 2005 NSPI deferred a portion of federal capital taxes and income
taxes reflecting increases in these taxes since rates were last set in 2002.
In its February 5, 2007 decision, the UARB approved amortization of the
deferred amount over an eight year period, beginning April 1, 2007.
NSPI has a $147.1 million regulatory asset related to pre-2003 income
taxes that have been paid, but not yet recovered from customers. In its
February 5, 2007 decision, the UARB approved recovery of this regulatory asset
over eight years, commencing April 1, 2007.
Outlook
Electricity sales volume (load) is expected to be higher in 2007 than in
2006 because the large industrial customer that was not operating for much of
2006 has restarted operations. Electric sales revenue will also increase due
to an approved 3.8% electricity price increase effective April 1, 2007.
Fuel costs are expected to increase primarily due to the expected increase
in sales volume noted above, and higher commodity prices, particularily oil.
NSPI will begin recovery of previously deferred and paid taxes on April 1,
2007, which will be reflected in regulatory amortization.
Other costs of NSPI are generally expected to remain consistent with 2006
levels.
Debt Management
There were no new long-term debt issuances in 2006.
In Q4 2005, NSPI issued a $150 million medium-term note at a coupon rate
of 5.67% maturing November 14, 2035. Proceeds were used to pay down short-term
debt.
Earlier in 2005, NSPI issued a $100 million medium-term note at a coupon
rate of 4.22% maturing May 17, 2010. The proceeds were used to refinance
$100 million 8.38% medium-term notes that matured on that date.
The weighted average coupon rate on NSPI's outstanding medium-term and
debenture notes at December 31, 2006, was 6.86% (2005 - 6.83%). Approximately
38% of the debt matures over the next ten years; 58% matures between 2017 and
2036; and $50 million, or 4%, matures in 2097. The quoted market-weighted
average interest rate for the same or similar issues of the same remaining
maturities was 5.10% as of December 31, 2006 (2005 - 4.96%).
NSPI has established the following available credit facilities:
Short-term Maximum
millions of dollars Maturity amount
-------------------------------------------------------------------------
Commercial paper, with 100% backup
line of credit 1 Year Revolving $400.0
Operating credit facility 3 Year Revolving $100.0
-------------------------------------------------------------------------
In June 2006, Standard & Poor's ("S&P") rating agency lowered the
corporate and senior unsecured debt credit ratings of Nova Scotia Power to
BBB/Stable Outlook from BBB+/Negative Outlook. The ratings on NSPI's preferred
shares were lowered to P-3(high) from P-2(low). NSPI's commercial paper
program rating remained unchanged at A2. S&P cited concerns related to the
recovery of fuel-related expenses under the current regulatory framework in
Nova Scotia; an evolving fuel procurement strategy; and upcoming challenges
related to the approval, financing, and execution of several proposed capital
projects as reasons for the change.
In October 2005, Moody's rating agency revised NSPI's rating outlook to
negative from stable citing Nova Scotia Power fuel cost recovery concerns and
regulatory uncertainty.
The change could have cost implications for Nova Scotia Power as the
company re-finances existing debt in future years, issues new capital, or
enters into new fuel procurement arrangements.
The ratings issued by Dominion Bond Rating Service ("DBRS") are unchanged.
NSPI has the following available credit ratings:
DBRS S&P Moody's
-------------------------------------------------------------------------
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------
Corporate A (low) A (low) BBB BBB+ Baa1 N/A
Senior
unsecured
debt A (low) A (low) BBB BBB+ Baa1 Baa1
Preferred Pfd-2 Pfd-2 P-3 P-2 N/A N/A
stock (low) (low) (high) (low)
Commercial R-1 R-1 A-2 A-2 P-2 P-2
paper (low) (low) (Cdn) (Cdn) (Baa) (Baa)
-------------------------------------------------------------------------
Outlook
Based on the company's available credit and credit ratings, and past
experience, NSPI expects to have access to capital when needed.
BANGOR HYDRO-ELECTRIC COMPANY
All amounts in the Bangor Hydro section are reported in US dollars unless
otherwise stated.
Overview
Bangor Hydro is the second largest electric utility in Maine.
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 owns and operates approximately
950 kilometers of transmission facilities, and 7,900 kilometers of
distribution facilities. BHE is currently investing approximately $120 million
in the Northeast Reliability Interconnect ("NRI"), an international
electricity transmission line connecting New Brunswick to Maine, which is
expected to be in service in late 2007. BHE has a workforce of approximately
240 people.
In addition to T&D assets, BHE has net "regulatory" assets (stranded
costs), which arose through the restructuring of the electricity industry in
the state in the late 1990s; and as a result of rate and accounting orders
issued by its regulator. BHE's net regulatory assets primarily include the
costs associated with the buy-out/restructuring of above-market power purchase
contracts; and the unamortized portion on its loss on the sale of its
investment in the Seabrook nuclear facility. Unlike T&D operational assets,
which are generally sustained with new investment, the regulatory asset pool
diminishes over time, as elements are amortized through charges to earnings,
and recovered through rates. These regulatory assets total approximately
$63 million at December 31, 2006, or 11% of BHE's net asset base.
Approximately 55% of BHE's electric rate represents distribution service,
15% relates to stranded cost recoveries, and 30% to transmission service. The
rates for each element are established in distinct regulatory proceedings.
BHE's distribution operations and stranded costs are regulated by the Maine
Public Utilities Commission ("MPUC"). The transmission operations are
regulated by the Federal Energy Regulatory Commission ("FERC").
BHE's distribution service operates under an Alternate Rate Plan ("ARP"),
which provides for an earnings band of 5% to 17% return on equity on
distribution operations, with rates set at the midpoint of 11%. There is a
50/50 sharing mechanism between the company and customers outside of the
earnings band. The ARP also includes performance standards and provides for
average annual reductions in distribution rates of approximately 2.5% for five
years, to 2007.
BHE's stranded cost rates provide for an allowed return on equity of 10%
on the related asset base for the three-year period ending February 29, 2008.
In Q4 2006 BHE announced its intention to file a request for changes in
both its distribution rates and stranded cost rates, to go into effect Q1
2008. Bangor Hydro's filing requests an increase in distribution rates as a
result of shrinkage in overall load. This increase is substantially offset by
the requested reduction in stranded cost rates such that the net impact on
electric rates is minimal.
Transmission rates are set by the FERC annually on July 1, based on the
prior year's revenue requirement. The allowed ROE for transmission operations
was 11.25% through October 31, 2006. As a result of a recent FERC ruling, the
allowed ROE on transmission assets ranges from 10.9% for low voltage
transmission up to 12.4% for high voltage transmission developed as a result
of the regional system plan, which includes the NRI project.
Review of 2006
BHE Net Earnings
millions of dollars Three months Year
(except earnings ended ended
per common share) December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005 2004
-------------------------------------------------------------------------
T&D revenues $ 25.5 $ 25.9 $ 101.8 $ 105.5 $ 116.4
Resale of purchased
power 3.7 4.0 15.2 13.6 10.6
-------------------------------------------------------------------------
Total electric revenue 29.2 29.9 117.0 119.1 127.0
Fuel for generation
and purchased power 8.2 9.7 31.4 33.6 35.0
Operating, maintenance
and general 7.0 7.7 27.1 31.2 31.7
Property taxes 1.0 0.8 5.0 4.9 4.8
Depreciation 3.2 3.2 12.9 12.4 10.9
Regulatory amortization 2.0 1.1 12.6 10.8 15.2
Other (2.1) (0.8) (5.9) (3.9) (3.3)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 9.9 8.2 33.9 30.1 32.7
Interest 2.7 2.6 10.3 10.0 10.3
-------------------------------------------------------------------------
Earnings before income
taxes 7.2 5.6 23.6 20.1 22.4
Income taxes 2.6 2.2 8.8 7.8 8.0
-------------------------------------------------------------------------
Contribution to
consolidated
net earnings - US $ $ 4.6 $ 3.4 $ 14.8 $ 12.3 $ 14.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings - Canadian $ $ 5.3 $ 4.0 $ 16.8 $ 14.9 $ 18.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share -
Canadian $ $ 0.04 $ 0.04 $ 0.15 $ 0.14 $ 0.17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted
average foreign
exchange rate -
Canadian /US $ $ 1.15 $ 1.17 $ 1.13 $ 1.21 $ 1.30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was $4.6 million
in Q4 2006 compared to $3.4 million in Q4 2005. For the year ended December
31, 2006, Bangor Hydro's contribution to consolidated net earnings was
$14.8 million, compared to $12.3 million in 2005 and $14.4 million in 2004.
Highlights of the earnings changes are summarized in the following table:
Three
months Year
ended ended
December December
millions of dollars 31 31
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2004 $ 14.4
Increased energy sales volume 1.8
Increased depreciation expense,
reflecting new depreciation study (1.5)
2004 stranded cost purchased
power expense less than amount used in
setting rates (1.1)
Increased NEPOOL related transmission
expenses (0.9)
Write-off in Q2 2004 of deferred costs
disallowed in rates 1.1
All other (1.5)
-------------------------------------------------------------------------
Contribution to consolidated
net earnings - 2005 $ 3.4 $ 12.3
Increased overheads capitalized primarily
as a result of capital expenditures on
the Northeast Reliability Interconnect
transmission project 2.6 5.2
Decreased energy sales largely due to
warmer weather year over year (0.4) (1.8)
All other (1.0) (0.9)
-------------------------------------------------------------------------
Contribution to consolidated
net earnings - 2006 $ 4.6 $ 14.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was
$5.3 million CAD in Q4 2006 compared to $4.0 million CAD in Q4 2005, due to
the Canadian dollar equivalent of the variances discussed above and the
$0.1 million impact of the stronger Canadian dollar. For the year ended
December 31, 2006, net earnings contributed by Bangor Hydro was $16.8 million
CAD compared to $14.9 million CAD for 2005 and $18.5 million CAD for 2004, due
to the Canadian dollar equivalent of the variances discussed above and the
$1.1 million impact of the stronger Canadian dollar in 2006 and $1.0 million
impact of the stronger Canadian dollar in 2005.
Electric Revenue
Q4 Electric Sales Volume Q4 Electric Sales Revenues
GWh millions of dollars
------------------------------------ -----------------------------------
2006 2005 2004 2006 2005 2004
------------------------------------ -----------------------------------
Residential 155 157 156 Residential $ 12.9 $ 13.0 $ 14.6
Commercial 141 147 150 Commercial 8.8 9.0 10.4
Industrial 93 100 102 Industrial 2.8 2.8 3.6
Other 3 3 3 Other 1.0 1.1 1.1
------------------------------------ -----------------------------------
Total 392 407 411 Total $ 25.5 $ 25.9 $ 29.7
------------------------------------ -----------------------------------
------------------------------------ -----------------------------------
YTD Electric Sales Volume YTD Electric Sales Revenues
GWh millions of dollars
------------------------------------ ------------------------------------
2006 2005 2004 2006 2005 2004
------------------------------------ ------------------------------------
Residential 589 603 594 Residential $ 49.1 $ 51.1 $ 56.0
Commercial 598 610 603 Commercial 36.1 37.0 42.1
Industrial 372 404 359 Industrial 11.3 12.4 14.2
Other 12 12 12 Other 5.3 5.0 4.1
------------------------------------ ------------------------------------
Total 1,571 1,629 1,568 Total $101.8 $105.5 $116.4
------------------------------------ ------------------------------------
------------------------------------ ------------------------------------
Q4 Average Revenue / MWh
------------------------------------
2006 2005 2004
------------------------------------
Dollars per
MWh $ 65 $ 64 $ 72
------------------------------------
------------------------------------
YTD Average Revenue / MWh
------------------------------------
2006 2005 2004
------------------------------------
Dollars per
MWh $ 65 $ 65 $ 74
------------------------------------
------------------------------------
Electric sales volume is primarily driven by general economic conditions,
population and weather. Electric sales pricing in Maine is regulated, and
therefore changes in accordance with regulatory decisions.
Electric revenues decreased by $0.4 million in Q4 2006, to $25.5 million
compared to $25.9 million in Q4 2005. For the year ended December 31, 2006,
electric revenues were $101.8 million compared to $105.5 million for 2005 and
$116.4 million in 2004. Highlights of the changes are summarized in the
following table:
Three
months Year
ended ended
December December
millions of dollars 31 31
-------------------------------------------------------------------------
T&D revenues - 2004 $ 116.4
Stranded cost rate reduction on
March 1, 2005 (13.0)
Increased energy sales volume 1.8
All other 0.3
-------------------------------------------------------------------------
T&D revenues - 2005 $ 25.9 $ 105.5
Stranded cost rate reduction on
March 1, 2005 - (2.7)
Decreased energy sales volume due to
warmer weather year over year (0.4) (1.8)
All other - 0.8
-------------------------------------------------------------------------
T&D revenues - 2006 $ 25.5 $ 101.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Resale of Purchased Power, and Fuel for Generation and Purchased Power
The company has several above-market purchase power contracts pre-dating
the Maine market restructuring. Power purchased under these arrangements is
resold to a third party at market rates. Resale of purchased power increased
in 2006 and 2005 due to increases in the rate at which BHE's power purchases
were resold to a third party.
Operating, Maintenance and General Expenses
Operating, maintenance and general expenses decreased $0.7 million to $7.0
million in Q4 2006 compared to $7.7 million in 2005 and decreased $4.1 million
to $27.1 million for the year ended December 31, 2006, compared to $31.2
million in 2005 primarily due to increased overheads capitalized primarily as
a result of capital expenditures on the Northeast Reliability Interconnect
("NRI") transmission project.
Operating, maintenance and general expenses decreased $0.5 million to
$31.2 in 2005 from $31.7 million in 2004, primarily due to reduced labour.
Depreciation
Depreciation expense was unchanged at $3.2 million in Q4 2006 compared to
Q4 2005; increased $0.5 million in 2006 relative to 2005; and increased
$1.5 million in 2005 relative to 2004, due principally to the effect of plant
additions. The results of BHE's depreciation study, completed in 2004, also
affected the results.
Regulatory Amortization
Regulatory amortization was $0.9 million higher in Q4 2006 at
$2.0 million, compared to $1.1 million in Q4 2005 and was $1.8 million higher
year-to-date 2006 at $12.6 million, compared to $10.8 million for the same
period in 2005, primarily due to the new stranded cost levelizer amortization,
implemented with the stranded cost rate reduction effective March 1, 2005.
For the year ended December 31, 2005 amortization expense was
$10.8 million, compared to $15.2 million in 2004, a reflection of the new
stranded cost levelizer deferral.
Other
Other income was $2.1 million in Q4 2006 compared to $0.8 million in Q4
2005 and $5.9 million in 2006, compared to $3.9 million for 2005 primarily due
to increased allowance for funds used during construction related to NRI
capital expenditures.
Interest
Bangor Hydro manages exposure through a combination of fixed and floating
rate borrowings.
Income Taxes
Bangor Hydro uses the future income tax method of accounting for income
taxes.
Bangor Hydro is subject to corporate income tax at the statutory rate of
40.8% (combined federal and state).
Outlook
Bangor Hydro net earnings are expected to be higher in 2007, as the
Northeast Reliability Interconnect is constructed and comes into operation in
Q4 2007.
Debt Management
The weighted-average coupon rate on Bangor Hydro's long-term debt
outstanding at December 31, 2006 was 7.22% (2005 - 7.18%). Approximately 60%
of the debt matures over the next 12 years; the remaining issues mature in
2020 and 2022. The quoted market-weighted-average interest rate for the same
or similar issues of the same remaining maturities was 5.86% as of December
31, 2006 (2005 - 5.55%).
Bangor Hydro has established the following credit facilities:
Short-term Maximum
millions of dollars Maturity amount
-------------------------------------------------------------------------
Operating Credit facility 3 year revolving $ 70.0
-------------------------------------------------------------------------
Bangor Hydro has no public debt, and accordingly has no requirement for
public credit ratings. Bangor Hydro believes that its credit facility provides
adequate access to capital to support current operations and a base level of
capital expenditures. For additional capital needs, BHE expects to have
sufficient access to competitively priced funds in the unsecured debt market.
Outlook
BHE will finance a portion of the Northeast Reliability Interconnect
project with debt in 2007. The remainder of the project was funded internally
through the sale of common shares in BHE to Emera Inc. in Q4 2006.
OTHER, INCLUDING CORPORATE COSTS
All activities of Emera other than its two regulated electric utilities
are incorporated into Other, including:
- Emera Energy Services 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.
- A 12.9% interest in the $2 billion, 1,300 kilometer Maritimes &
Northeast Pipeline that transports Nova Scotia's offshore natural gas
to markets in Maritime Canada and the northeastern United States.
- Bear Swamp, a 50/50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts, which was acquired
on May 24, 2005. As a pumped storage hydro-electric facility, the plant
typically purchases power during lower priced off peak periods and
generates power during higher priced on peak periods.
- 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.
Acquisition of Bear Swamp
In Q2 2005 Emera and Brookfield Power Corporation, in a 50/50 joint
venture, acquired Bear Swamp, a 600 MW pumped storage hydro-electric facility
in northern Massachusetts. Emera's share of the purchase price was
$61.2 million including acquisition costs. The facility sells energy, capacity
and ancillary products to the New England Power Pool. Also included in the
acquisition is the nearby 10 MW Fife Brook run-of-river hydro-electric
facility.
The acquisition has been accounted for under the purchase method of
accounting using proportionate consolidation, and accordingly, Emera's pro-
rata share of the results of operations since the date of acquisition have
been included in the consolidated statement of earnings and the summary
statement of earnings below.
Investment in Brunswick Pipeline
Brunswick Pipeline is a proposed $350 million 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 145 kilometer Brunswick Pipeline
will travel through southwest New Brunswick and connect with the Maritimes and
Northeast Pipeline at the Canada/US border near Baileyville, Maine. Emera has
been an investor in M&NP since its inception in 1999.
Canaport(TM) LNG is a partnership of Repsol YPF, S.A. and Irving Oil
Limited. Emera has negotiated a a 25 year send or pay toll agreement with
Repsol to transport natural gas through the Brunswick Pipeline. Emera has also
negotiated agreements with its M&NP partner, Spectra Energy Corp, an affiliate
of which will assist Emera in the Brunswick Pipeline permitting process, and
construct and operate the pipeline on Emera's behalf.
Emera expects to finance the investment with internally generated cash
flow and debt. The investment is forecast to provide a return on project
equity of 11% - 14%.
The project requires National Energy Board approval. NEB hearings were
completed in November 2006, with a decision expected in Q2 2007. Assuming
approval is granted, the pipeline is expected to be in service by the end of
2008.
Until the NEB approves the Brunswick Pipeline, Emera is being reimbursed
by Repsol for project development costs. Accordingly, this project had no
significant effect on Emera's earnings or cash flows in 2006.
Emera's net cash requirements related to Brunswick Pipeline are expected
to be $65 million for 2007.
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 US $22 million in
January 2007.
Lucelec has an exclusive license to generate, transmit and distribute
electricity on the island to 2045. The utility has 66 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 to $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.
Sale of Assets of Emera Fuels
Effective Q3 2005 Emera sold its heating oil distribution business for
proceeds of $18.6 million, which were used to pay down debt. A loss on
disposition of $1.6 million after-tax was recognized in Q3 2005. The
transaction reduced Emera's total assets by approximately $25 million (net
assets by approximately $20 million). The reduction in annual after-tax net
earnings and cash provided by operating activities is immaterial.
Review of 2006
Three
Other Net Earnings months Year
millions of dollars ended ended
(except earnings per December December
common share) 31 31
-------------------------------------------------------------------------
2006 2005 2006 2005 2004
-------------------------------------------------------------------------
Emera Energy Services
earnings before
interest
and taxes ("EBIT") $ 4.6 $ 3.9 $ 15.1 $ 18.3 $ 17.7
Bear Swamp EBIT (0.8) 1.7 1.4 4.2 -
M&NP equity earnings 1.2 1.7 4.9 6.5 6.2
Corporate Costs & Other (3.6) (0.2) (9.6) (7.0) (15.6)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 1.4 7.1 11.8 22.0 8.3
Interest 3.6 9.5 10.0 7.4 13.2
-------------------------------------------------------------------------
Earnings before income
taxes (2.2) (2.4) 1.8 14.6 (4.9)
Income taxes (0.5) (2.1) (2.9) (1.4) (6.7)
-------------------------------------------------------------------------
Net earnings from
continuing operations (1.7) (0.3) 4.7 16.0 1.8
(Loss) earnings from
discontinued operations,
net of tax - - - (0.9) 2.2
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings $ (1.7) $ (0.3) $ 4.7 $ 15.1 $ 4.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidation earnings
per share $ (0.1) $ - $ 0.05 $ 0.14 $ 0.04
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The contribution of Other to consolidated net earnings was $(1.7) million
in Q4 2006, compared to $(0.3) million in Q4 2005. Annual contribution to
consolidated net earnings was $4.7 million in 2006 compared to $15.1 million
in 2005 and $4.0 million in 2004. Highlights of the earnings changes are
summarized in the following table:
Three
months Year
ended ended
December December
millions of dollars 31 31
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $ 4.0
Increased EBIT in Emera Energy Services as a result
of increased marketing opportunities 0.6
Addition of Bear Swamp hydro-electric
facilities EBIT 4.2
Foreign exchange gains reflecting an adjustment to
refine prior years' foreign exchange 5.2
Capitalization of previously expensed business
development costs to the Bear Swamp cost of net
assets purchased 2.5
Loss on disposition of Emera Fuels, net of tax (1.6)
Write-off of Greyhawk Gas Storage venture in Q1 2004 1.9
All other (1.7)
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $ (0.3) $ 15.1
Increased (decreased) EBIT in Emera Energy Services
as a result of increased (decreased) natural gas
marketing opportunities 0.7 (3.2)
Reduced Bear Swamp EBIT due to decreased electric
margin and mark-to-market losses related
to 2007 hedged positions (2.5) (2.8)
Loss in Emera Fuels in 2005, net of tax - 0.9
Capitalization in Q4 2005 of previously
expensed business development costs to the Bear
Swamp cost of net assets purchased (2.5) (2.5)
Reversal of foreign exchange gain in Q4 2005 that
had been recognized earlier in 2005 related to
settlement of US denominated debt 5.9 -
Foreign exchange gains recognized in 2005
reflecting an adjustment to refine prior years'
foreign exchange - (5.2)
All other (3.0) 2.4
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2006 $ (1.7) $ 4.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Emera Energy Services
Emera Energy Services EBIT increased quarter over quarter to $4.6 million
in Q4 2006 from $3.9 million in Q4 2005 as a result of increased volatility in
natural gas markets. For the year ended December 31, 2006 EBIT decreased to
$15.1 million from $18.3 million in 2005 as a result of moderating margins in
natural gas markets. For the year ended December 31, 2005 EBIT was
$18.3 million compared to $17.7 million in 2004 due to increased weather
related volatility in the market, including gains on longer term contracts in
2005.
Bear Swamp
Bear Swamp EBIT represents Emera's investment in the Bear Swamp joint
venture, which was acquired in Q2 2005.
Bear Swamp incurred a loss before interest and taxes of $0.8 million in Q4
2006 compared to earnings of $1.7 million in Q4 2005; and $1.4 million in 2006
compared to earnings of $4.2 million for the same period in 2005. In 2005 Bear
Swamp's margins were strong, because peak prices rose as a result of the
impact of an active hurricane season. During 2006, margins were weaker due to
milder weather patterns. A hedging program was implemented in 2006 to provide
more consistent margins and resulted in a mark-to-market loss, which will
reverse in 2007.
M&NP Equity Earnings
Equity earnings for M&NP were $1.2 million in Q4 2006 compared to
$1.7 million in Q4 2005, and were $4.9 million year-to-date 2006 compared to
$6.5 million for the same period in 2005 primarily due to expansion costs
expensed pending regulatory approval.
For the year ended December 31, 2005 M&NP equity earnings were
$6.5 million compared to $6.2 million in 2004. Increases in tolls collected
for the US operations have been offset by the write-off of previously expensed
cost for pipeline expansion on the US pipeline.
On May 16, 2006 M&NP filed an application with the FERC to expand its US
pipeline system to carry volumes from the proposed Brunswick Pipeline to
markets in the US northeast. Construction of the proposed expansion facilities
is anticipated to begin in June 2007, in conjunction with the building of
Brunswick Pipeline. M&NP is expensing development costs associated with the
expansion. Once FERC approval is obtained, likely in 2007, these will be
capitalized as part of the US pipeline expansion.
In 2004 M&NP filed a Notice of Rate Increase for its US operations.
Effective January 1, 2005 M&NP was permitted to collect proposed rates from
customers, pending approval of new rates. On June 28, 2005 M&NP submitted an
offer of settlement to the FERC, which was approved without modification on
May 15, 2006. The company had been recognizing its best estimate of rates in
equity earnings and energy marketing margin in Emera Energy Services based on
the terms of the proposed settlement. As a result, there were no adjustments
to earnings to account for the approved new rates.
Corporate Costs & Other
Expenses related to Corporate Costs & Other increased quarter over quarter
to $3.6 million in Q4 2006 from $0.2 million in Q4 2005; and increased year
over year to $9.6 million in 2006 from $7.0 million in 2005 largely as a
result of the capitalization in Q4 2005 of previously expensed business
development costs to the Bear Swamp cost of net assets purchased, partially
offset by dividend income received in 2006.
For the year ended December 31, 2005 expenses related to Corporate Costs &
Other decreased to $7.0 million from $15.6 million in 2004 largely due to the
write-off in 2004 of the Greyhawk Gas Storage Venture, partially offset by the
capitalized business development costs in 2005 referred to above.
Interest
Interest expense decreased quarter over quarter to $3.6 million in Q4 2006
from $9.5 million in Q4 2005 as a result of a foreign exchange gain reversing
in Q4 2005 that had been recognized earlier in the year.
For the year ended December 31, 2006, interest increased to $10.0 million
from $7.4 million in 2005 largely as a result of foreign exchange gains
recognized in 2005 reflecting an adjustment to prior years' foreign exchange.
For the year ended December 31, 2005 interest decreased to $7.4 million
from $13.2 million in 2004 largely due to the foreign exchange gains
recognized in 2005 as referred to above.
Income Taxes
All businesses included in Other follow the future income taxes method of
accounting for income taxes. Taxes are recognized on pre-tax income, excluding
M&NP equity earnings that are recorded net of tax. Variations in income tax
expense are largely affected by withholding taxes paid on cross-border
dividends and interest, completion of prior years' tax returns, and corporate
tax sharing agreements.
Outlook
Other net earnings are expected to increase marginally in 2007.
M&NP equity earnings are expected to increase due to the proposed tolling
agreement related to the Canadian portion of the investment; and
capitalization of expansion costs in the US in 2007 that were expensed in 2006
and prior years.
Bear Swamp EBIT is expected to increase in 2007 as a result of the
reversal of a mark-to-market loss recognized in 2006 related to 2007 hedge
positions and new capacity revenues.
Other net earnings will also include allowance for funds under
construction related to the Brunswick Pipeline in 2007.
Emera Energy Services EBIT is expected to decrease in 2007. SOEP gas
compression will increase the volume of gas out of SOEP and reduce the
opportunity to manage fluctuations in gas supply, which in turn will reduce
margins on gas sales.
Corporate and Other expenditures are expected to increase in 2007
reflecting increased business development activities and dividend income
received in 2006.
Debt Management
In June 2006, Emera amended its operating and acquisition credit
facilities by combining its $200 million operating facility and $400 million
acquisition facility into one $600 million facility for operating and
acquisition financing requirements.
Emera has established the following credit facilities outside its
regulated electric utilities:
Short-term Maximum
millions of dollars Maturity amount
-------------------------------------------------------------------------
Operating and acquisition credit facility 1 Year Revolving $ 600.0
-------------------------------------------------------------------------
In Q2 2006, Standard & Poor's rating agency lowered the corporate and
senior unsecured debt credit ratings of Emera citing concerns related to the
recovery of fuel-related expenses under the current regulatory framework in
Nova Scotia; an evolving fuel procurement strategy; and upcoming challenges
related to the approval, financing, and execution of several proposed capital
projects as reasons for the change. The negative outlook was again confirmed
in Moody's December 2006 credit opinion report.
The change could have cost implications for Emera and Nova Scotia Power as
the companies re-finance existing debt in future years, issue new capital or
enter into new fuel procurement arrangements.
The ratings issued by Dominion Bond Rating Service and Moody's Investor
Services are unchanged.
Emera has the following available credit ratings:
DBRS S&P Moody's
-------------------------------------------------------------------------
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------
Long-term
corporate BBB(high) BBB(high) BBB BBB+ Baa2 N/A
Senior
unsecured
debt BBB(high) BBB(high) BBB BBB Baa2 Baa2
-------------------------------------------------------------------------
On a consolidated basis, Emera's target percentage of debt to total
capitalization is 50%-55%, of which 10%-25% would be exposed to short-term
rates. The company manages long-term debt terms such that the average is not
less than ten years.
CONSOLIDATED BALANCE SHEETS
Significant changes in the consolidated balance sheets between December
31, 2006 and December 31, 2005 include:
Increase
millions of dollars (Decrease) Explanation
-------------------------------------------------------------------------
Cash and cash $ (13.9) Refer to the consolidated cash
equivalents flows highlights section below.
Accounts receivable 21.8 2005 and 2006 electricity price
increases, lower accounts
receivable securitization, and the
reclassification of the natural gas
price adjustment from long-term
receivables in NSPI, partially
offset by payment of the receivable
from Pengrowth, and decreased
pricing in Emera Energy Services.
Inventory 37.5 Higher fuel inventory levels and
pricing in NSPI.
Prepaid expenses 38.0 Increased posted margin paid to
counterparties in Emera Energy
Services.
Energy marketing assets 19.2 Increased long-term deal activity
(including long-term in Emera Energy Services and the
portion) addition of Bear Swamp in Q2 2005.
Energy marketing assets, net of
energy marketing liabilities, has
decreased due the realization of
long-term contracts.
Long-term receivables (48.4) Reclassification of the natural gas
price adjustment in NSPI to
accounts receivable.
Deferred charges (44.8) On-going amortization and a
reduction in NSPI's deferred
pension asset.
Property, plant and 52.7 Capital additions, including the
equipment and NRI project and Brunswick Pipeline,
construction in excess of depreciation expense.
work-in-progress
Short-term debt 45.1 Increased borrowings to finance NRI
project and increased posted margin
requirements from Emera Energy
Services' counterparties.
Accounts payable and 37.4 Timing of payments and increased
accrued charges accruals in NSPI, increased NRI-
related accruals, and a payable
related to the Brunswick Pipeline
project, partially offset by
pricing in Emera Energy Services.
Income tax payable 37.8 NSPI's tax expense in excess of
installments.
Energy marketing 23.1 Increased long-term deal activity
liabilities in Emera Energy Services and the
(including long-term addition of Bear Swamp in Q2 2005.
portion)
Deferred credits (11.4) Reduction in BHE's Maine Yankee
decommissioning liability and
deferred pension liability.
Long-term debt (123.9) Reduction in NSPI's Commercial
(including Paper due to increased cash flow
current portion) from operations.
Shareholders' equity 41.9 Net earnings in excess of common
dividends paid, and common shares
issued as a result of stock options
being exercised and stock purchase
plans.
-------------------------------------------------------------------------
OUTSTANDING SHARE DATA
Common
Share
Capital
Millions millions
of of
Issued and Outstanding: Shares dollars
-------------------------------------------------------------------------
January 1, 2005 108.87 $1,017.3
Issued for cash under purchase plans 0.43 7.9
Options exercised under senior management
share option plan 0.80 13.0
Share-based compensation - 1.0
-------------------------------------------------------------------------
December 31, 2005 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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at January 31, 2007 the number of issued and outstanding common shares
was 110.98 million.
Liquidity and Capital Resources
The company generates funds primarily through its operations in regulated
utilities involving the generation, transmission and distribution of
electricity. Circumstances that could affect the company's ability to generate
funds include fuel commodity price changes, general economic downturns in Nova
Scotia and Maine, and regulatory decisions affecting customer rates. In
addition to internally generated funds, the company has access to debt capital
markets, including $782 million in syndicated bank lines of credit, a
$400 million commercial paper program, which is 100% backed up by a syndicated
bank line of credit, and an $80 million accounts receivable securitization
program. The company's financing facilities are expected to provide sufficient
access to money markets and capital markets necessary to maintain acceptable
levels of liquidity relative to current cash forecasts.
Emera and Nova Scotia Power have debt shelf prospectuses in the amounts of
$300 million and $400 million respectively that provide the companies with
access to long-term debt. Emera and Nova Scotia Power have $300 million and
$150 million respectively that remained unused at December 31, 2006. The
prospectuses expire in April 2007 and will be renewed. The company also has
access to equity capital markets for both common and preferred shares.
Consolidated Cash Flow Highlights
Significant changes in the consolidated cash flow statements between
December 31, 2006 and December 31, 2005 include:
Three months ended
December 31
millions of dollars 2006 2005 Explanation
-------------------------------------------------------------------------
Cash and cash
equivalents,
beginning of period $ 4.5 $ 19.2
Provided by (used in):
Operating activities 106.7 (36.3) In 2006, cash earnings and
improved non-cash working
capital.
In 2005, reduced non-cash
working capital, partially
offset by cash earnings.
Investing activities (83.0) 58.5 In 2006, capital spending,
including NRI project.
In 2005, return of the
escrow deposit made on a
proposed acquisition,
decreased restricted cash,
and proceeds received on
the sale of Emera Fuels,
partially offset by capital
spending.
Financing activities (20.6) (19.9) In 2006, reduced debt levels
and dividends on common
shares.
In 2005, reduced debt levels
and dividends on common
shares, partially offset by
increased accounts
receivable securitized and
receipt from long-term
Pengrowth receivable.
-------------------------------------------------------------------------
Cash and cash
equivalents,
end of year $ 7.6 $ 21.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year ended December 31
millions of dollars 2006 2005 Explanation
-------------------------------------------------------------------------
Cash and cash
equivalents,
beginning of period $ 21.5 $ 42.7
Provided by (used in):
Operating activities 345.8 164.3 In 2006, cash earnings,
partially offset by reduced
non-cash working capital.
In 2005, cash earnings,
partially offset by reduced
non-cash working capital.
Investing activities (203.0) (117.2) In 2006, capital spending,
including NRI project.
In 2005, capital spending
and the acquisition of Bear
Swamp, partially offset by
the return of escrow deposit
made on a proposed
acquisition and proceeds
received on the sale of
Emera Fuels.
Financing activities (156.7) (68.3) In 2006, dividends on common
shares, reduction in debt
levels, and decrease in the
amount of accounts
receivable securitized,
partially offset by common
shares issued.
In 2005, dividends on common
shares, partially offset by
common shares issued and
receipt from long-term
Pengrowth receivable.
-------------------------------------------------------------------------
Cash and cash
equivalents,
end of year $ 7.6 $ 21.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contractual Obligations
The consolidated contractual obligations over the next five years and
thereafter include:
millions of dollars Payments Due by Period
-------------------------------------------------------------------------
2008- 2010- After
Total 2007 2009 2011 2011
-------------------------------------------------------------------------
Long-term debt $1,660.8 $ 171.4 $ 251.7 $ 110.6 $1,127.1
Operating leases 29.6 7.4 12.9 6.4 2.9
Purchase obligations 1,821.8 441.8 619.6 304.9 455.5
Other long-term
obligations 316.9 0.8 0.9 2.0 313.2
-------------------------------------------------------------------------
Total contractual
obligations $3,829.1 $ 621.4 $ 885.1 $ 423.9 $1,898.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating lease obligations: Emera's operating lease obligations consist
of operating lease agreements for office space, telecommunications services,
vehicles, and photocopiers.
Purchase obligations: Emera has purchasing commitments for electricity
from independent power producers, transportation of coal, outsource management
of the company's computer infrastructure, natural gas, transportation capacity
on the Maritimes & Northeast Pipeline, and fuel.
Other long-term obligations: The company has asset retirement and other
long-term obligations.
The company expects to be able to meet its obligations with cash flows
generated from operations.
Capital Resources
Capital expenditures for 2006 were approximately $200 million.
Significant capital projects included
- $62 million CAD related to Northeast Reliability Interconnect project
in BHE,
- Installation of a Low Nox Combustion Firing system on NSPI's Lingan
Unit 3,
- Installation of turbine blades at NSPI's Tufts Cove 1, and
- A transmission line upgrade in BHE.
In December 2006, NSPI filed work orders for approval by the UARB for the
following capital projects:
- Installation of a Low NOx Combustion Firing system on Lingan Units 2
and 4 at approximately $4 million each.
- Installation of a pulse air fabric filter baghouse on Trenton Unit 5
for approximately $30 million
- Rebuild of generator on Trenton Unit 5 for approximately $17 million
In November 2005, NSPI filed a Notice of Application for the construction
of capital projects associated with achieving the air emissions requirements
contained in the Provincial environmental regulations. These capital projects
are for the installation of air emissions abatement equipment at the Lingan
generating station. Total investment associated with this equipment was
projected at $177 million.
NSPI's regulator, the UARB, approved $5 million for the installation of a
Low NOx Combustion Firing system on Lingan Unit 3 on April 5, 2006, which has
now been installed. Nova Scotia Power requested to discontinue its application
for the remaining $172 million for the flue gas desulphurization equipment in
response to requests from stakeholders for more study. The UARB agreed with
NSPI's request. A hearing on this matter took place on June 19, 2006.
Participants in the hearing agreed to take part in an Integrated Resource Plan
("IRP"), which will analyze a variety of factors to assess how best to
proceed. The IRP is expected to be completed in Q3 of 2007.
Outlook
Emera's capital budget for 2007 includes approximately $120 million for
NSPI, which is generally directed to customer growth and system reliability,
planned and preventative maintenance, productivity-related investments, and
air emissions upgrades. BHE expects to invest approximately $90 million CAD,
including approximately $70 million CAD for several transmission projects.
Brunswick Pipeline expects to invest approximately $65 million.
The company expects to finance its capital expenditures with funds from
operations and debt. Bangor Hydro will finance a portion of the Northeast
Reliability Interconnect project with a long-term debt issue in 2007.
Off-Balance Sheet Arrangements
Upon privatization in 1992, NSPI became responsible for managing a
portfolio of approximately $1.05 billion of defeasance securities held in
trust. The defeasance securities must provide the principal and interest
streams to match the related defeased debt. Approximately 71% of the
defeasance portfolio consists of investments in the related debt, eliminating
all risk associated with this portion of the portfolio; the remaining
defeasance portfolio consists of investments with market values higher than
the related debt, reducing the future risk of this portion of the portfolio.
NSPI has an agreement with an independent trust administered by a Canadian
chartered bank whereby it can sell accounts receivable to the trust on a
revolving non-recourse basis. As of December 31, 2006, the company had sold
$80.0 million (2005 - $80.0 million) of net accounts receivable. The net
proceeds from the sale were used to repay a portion of the company's debt. The
agreement is in place until May 2009, with the intention that it will be
renewed at that time. Securitization provides NSPI with an alternative source
of short-term funding. For the year ended December 31, 2006, the average
all-in cost of this funding was 4.30% (2005 - 2.97%). In the event of
termination of this arrangement, NSPI would utilize another liquidity facility
to meet the ongoing operations of the business.
Financial and Commodity Instruments
The company manages its exposure to foreign exchange, interest rate, and
commodity risks in accordance with established risk management policies and
procedures. The company uses derivative instruments consisting mainly of
foreign exchange forward contracts, interest rate options and swaps, and oil
and gas options and swaps.
Instruments that meet stringent documentation requirements, and can be
proven to be effective both at the inception and over the term of the
instrument qualify for hedge accounting. Specifically, amounts paid or
received are deferred and recognized in earnings in the same period the
related hedged item is realized. Where the documentation or effectiveness
requirements are not met, the non-qualifying instruments are marked-to-market
and recognized in earnings in the reporting period.
The company has deferred payments and receipts on derivative instruments
that are designated and effective as hedges and are recognized in the
following categories on the balance sheet:
Deferred Hedging Losses Recognized on the Balance Sheet
millions of dollars
-------------------------------------------------------------------------
December December
31 31
2006 2005
-------------------------------------------------------------------------
Inventory $ 5.2 $ 0.2
Deferred charges 0.9 1.1
-------------------------------------------------------------------------
Deferred hedging losses $ 6.1 $ 1.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three month period and year ended December 31, the impacts of
effective hedges recognized in earnings were recorded in the following
categories:
Hedging Impact Recognized
in Earnings Three months ended Year ended
millions of dollars December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Fuel and purchased power
decrease (increase) $ 15.7 $ (3.9) $ 48.4 $ (20.5)
Interest expense increase (0.1) (0.4) (0.3) (1.9)
-------------------------------------------------------------------------
Hedging earnings impact $ 15.6 $ (4.3) $ 48.1 $ (22.4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company also enters into non-hedging derivative financial and
commodity instruments. These instruments, along with the non-qualifying hedges
referred to above, are marked-to-market at each reporting date.
The company had recorded the following mark-to-market transactions
included on the balance sheet and recognized in earnings.
Mark-to-Market Gains (Losses) Recognized on the Balance Sheet
millions of dollars
-------------------------------------------------------------------------
December December
31 31
2006 2005
-------------------------------------------------------------------------
Accounts receivable - $ 4.5
Energy marketing assets $ 39.3 20.1
Deferred charges - 0.4
Energy marketing liabilities (38.1) (15.0)
-------------------------------------------------------------------------
Mark-to-market gains $ 1.2 $ 10.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Mark-to-Market Gains (Losses)
Recognized in Earnings Three months ended Year ended
millions of dollars December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Other revenue $ 1.1 $ (0.5) $ (2.1) $ 4.6
Fuel and purchased power (2.1) 8.5 (6.4) 8.5
Interest (0.2) 0.4 (0.3) -
-------------------------------------------------------------------------
Mark-to-market (losses) gains $ (1.2) $ 8.4 $ (8.8) $ 13.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $6.2 million (2005 - $5.1 million) during the
three months ended December 31, 2006, and $29.3 million (2005 - $21.7 million)
during the year ended December 31, 2006, from the Maritimes & Northeast
Pipeline, an investment under significant influence of the company. The amount
is recognized in fuel for generation and purchased power or netted against
energy marketing margin in other revenue, and is measured at the exchange
amount. At December 31, 2006 the amount payable to the related party is
$3.4 million (December 31, 2005 - $4.5 million), is non-interest bearing and
is under normal credit terms.
Disclosure and Internal Controls
Emera's management is responsible for the design of disclosure controls
and procedures, as defined under Multilateral Instrument 52-109, for the year
ended December 31, 2006 in order to provide reasonable assurance that material
information is made known to them. Management is also responsible for the
design of internal controls over financial reporting in order to provide
reasonable assurance regarding the reliability of financial statements
prepared for external purposes in accordance with GAAP.
The President and Chief Executive Officer and the Chief Financial Officer,
with the assistance of company employees, have evaluated the effectiveness of
the design and operation of disclosure controls and procedures. Based on that
evaluation, the President and Chief Executive Officer and the Chief Financial
Officer have concluded that the company's disclosure controls and procedures
are adequate and effective in ensuring material information relating to Emera
and its consolidated subsidiaries is made known to them and is complete and
reliable.
The President and Chief Executive Officer and the Chief Financial Officer,
with the assistance of company employees, have evaluated the effectiveness of
the design of internal controls and procedures. Based on that evaluation, the
President and Chief Executive Officer and the Chief Financial Officer have
concluded that the design of these internal controls was effective.
There have been no changes in Emera's internal controls over financial
reporting during the quarter ended December 31, 2006, that have materially
affected, or are reasonably likely to materially affect, internal controls
over financial reporting.
Critical Accounting Estimates
The preparation of consolidated financial statements requires management
to make estimates and assumptions that affect the reported amounts of assets
and liabilities, related amounts of revenues and expenses, and disclosure of
contingent assets and liabilities. Significant areas requiring the use of
management estimates relate to rate regulation, the determination of
post-retirement employee benefits, unbilled revenue, natural gas price
adjustment receivable, asset retirement obligations, useful lives for
depreciable assets, and goodwill impairment assessments. Actual results may
differ from these estimates.
Rate Regulation
NSPI's and BHE's accounting policies are subject to examination and
approval by their respective regulators. As a result, their rate-regulated
accounting policies may differ from accounting policies for non-rate-regulated
companies. These differences occur when the regulators render their decisions
on rate applications or other matters and generally involve the timing of
revenue and expense recognition.
The accounting for these items is based on the expectation of the future
actions of the regulators. For example, NSPI does not record future income
taxes. The taxes payable method is prescribed by the regulator for rate-making
purposes and there is reasonable expectation that the regulator will provide
for all such future income taxes to be recovered in rates when they become
payable. Similarly, the deferral of differences between the amounts included
in rates and regulations and the realization of specified expenses is based on
the expectation that the regulators will approve the refund to or recovery
from ratepayers of the deferred balance.
If the regulators' future actions are different from the companies'
expectations, the timing and amount of the recovery of liabilities and refund
of assets, recorded or unrecorded, could be significantly different from that
reflected in the financial statements.
Pension and Other Post-Retirement Employee Benefits
The company provides post-retirement benefits to employees, including a
defined benefit pension plan. The cost of providing these benefits is
dependent upon many factors that result from actual plan experience and
assumptions of future experience.
The benefit cost and accrued benefit obligation for employee future
benefits included in annual compensation expenses are affected by employee
demographics, including age, compensation levels, employment periods,
contribution levels and earnings on plan assets.
Changes to the provision of the plan may also affect current and future
pension costs. Benefit costs may also be significantly affected by changes in
key actuarial assumptions, including anticipated rates of return on plan
assets and discount rates used in determining the accrued benefit obligation
and benefit costs.
The pension plan assets are comprised primarily of equity and fixed income
investments. Fluctuations in actual equity market returns and changes in
interest rates may result in increased or decreased pension costs in future
periods.
The following table reflects the sensitivities associated with a change in
certain actuarial assumptions. The impact of increasing the expected rate of
return on plan assets or the discount rate by 0.5% on the accrued benefit
obligation recorded in the 2006 year end consolidated financial statements and
the 2007 benefit cost and 2007 year end accrued benefit asset or liability
would be as follows:
-------------------------------------------------------------------------
millions of dollars NSPI BHE
-------------------------------------------------------------------------
Impact of increasing the rate of return
assumption by 0.5%:
Accrued benefit obligations, December 31, 2006 - -
Benefit cost for the year ended December 31, 2007 $ (3.0) $ (0.3)
Accrued benefit asset, December 31, 2007 $ 3.0 -
Accrued benefit liability, December 31, 2007 - $ (0.3)
Impact of increasing the discount rate assumption
by 0.5%:
Accrued benefit obligations, December 31, 2006 $ (61.4) $ (8.3)
Benefit cost for the year ended December 31, 2007 $ (6.7) $ (0.6)
Accrued benefit asset, December 31, 2007 $ 6.7 -
Accrued benefit liability, December 31, 2007 - $ (0.6)
-------------------------------------------------------------------------
The discount rate used to determine benefit costs is based on 'A' grade
long-term Canadian corporate bonds for NSPI's pension plan and US corporate
bonds for BHE's pension plan. The discount rate is determined with reference
to bonds which have the same duration as the accrued benefit obligation as at
January 1 of the fiscal year rounded to the nearest 25 basis points. NSPI's
rate was 5.25% for 2006, reduced from 6.0% for 2005 and BHE's rate was 5.75%
for 2006, reduced from 6.0% in 2005. The expected rate to be used for 2007 is
5.25% for NSPI and 6.00% for BHE.
The expected return on plan assets is based on management's best estimate
of future returns, considering economic and consensus forecasts. The 2006 and
2005 benefit cost calculations assumed that plan assets would earn a rate of
return of 7.5% for NSPI and 8.0% for BHE. The 2007 benefit cost calculation is
expected to use the same asset return assumptions.
Unbilled Revenue
Electric revenues are billed on a systematic basis over a one or two-month
period for NSPI and a one-month period for BHE. At the end of each month the
company must make an estimate of energy delivered to customers since the date
their meter was last read and of related revenues earned but not yet billed.
The unbilled revenue is estimated based on several factors, including current
month's generation, estimated customer usage by class, weather, line losses
and applicable customer rates. Based on the extent of the estimates included
in the determination of unbilled revenue, actual results may differ from the
estimate. As of December 31, 2006, unbilled revenues amount to $82.3 million
(2005 - $71.8 million) on a base of annual electric revenues of approximately
$1.1 billion (2005 - $1.1 billion).
Natural Gas Price Adjustment Receivable
NSPI's existing long-term natural gas purchase agreement includes a price
adjustment clause covering three years of natural gas purchases. The clause
states that NSPI will pay for all gas purchases at the agreed contract price,
but will be entitled to a price rebate on a portion of the volumes to be
settled in November 2007. Management has made a best estimate of the price
rebate based on the contract specifications using actual and forward marketing
pricing and recorded it in accounts receivable.
Asset Retirement Obligations
The company recognizes asset retirement obligations for property, plant
and equipment in the period in which they are incurred if a reasonable
estimate of fair value can be determined. The fair value of the liability is
described as the amount at which the liability could be settled in a current
transaction between willing parties. Expected values are discounted at the
risk-free interest rate adjusted to reflect the market's evaluation of the
company's credit standing. Determining asset retirement obligations requires
estimating the life of the related asset and the costs of activities such as
demolition, restoration and remedial work based on present-day methods and
technologies.
As part of the 2003 NSPI depreciation settlement, the UARB included the
amount of future expenditures associated with the removal of generation
facilities. NSPI believes that it will continue to be able to recover asset
retirement obligations through rates. Accordingly, changes to the asset
retirement obligations, or cost recognition attributable to changes in the
factors discussed above, should not impact the results of operations of the
company.
At December 31, 2006, the asset retirement obligations recorded on the
balance sheet were $78.1 million (2005 - $74.1 million). The company estimates
the undiscounted amount of cash flow required to settle the obligations is
approximately $315.9 million, which will be incurred between 2007 and 2061.
The majority of these costs will be incurred between 2020 and 2039.
Property, Plant and Equipment
Property, plant and equipment represents 71% of total assets recognized on
the company's balance sheet. Included in property, plant and equipment are the
generation, transmission and distribution and other assets of the company. Due
to the size of the company's property, plant and equipment, changes in
estimated depreciation rates can have a significant impact on depreciation
expense.
Depreciation is calculated on a straight-line basis over the estimated
service life of the asset. The estimated useful lives of the assets are
largely based on formal depreciation studies, which are conducted from time to
time.
In 2002 NSPI commissioned a depreciation study by an external consultant.
The study was filed with the UARB in 2003. A settlement agreement on the
matter was reached with all intervenors, which recommended a four-year
phase-in of new depreciation rates, which, based on assets in service in the
study, would reach an overall increase of $20 million by 2007. The UARB
approved the settlement. NSPI began phasing the new rates in 2004. In its rate
decision for 2005, the UARB deferred the scheduled phase-in for 2005. In the
rate decision for 2006, the UARB included the phase-in of year 2 in rates. In
its February 5, 2007 decision, the UARB postponed the phase-in of year 3 rates
until the next rate application.
In 2004 Bangor Hydro completed a depreciation study. The study concluded
that the company's accumulated depreciation was understated by approximately
$6.6 million. The company received approval from FERC to implement the results
of the depreciation study effective January 1, 2004. As a result of the study,
Bangor Hydro began amortizing the $6.6 million over the average remaining
service lives of the major plant asset classifications. Bangor Hydro also
adjusted the composite depreciation rates for 2004 to reflect shorter lives as
recommended by the study.
Goodwill Impairment Assessments
Goodwill represents the excess of the acquisition purchase price for
Bangor Hydro over the fair values assigned to individual assets acquired and
liabilities assumed. Emera is required to perform an impairment assessment
annually, or in the interim if an event occurs that indicates that the fair
value of Bangor Hydro may be below its carrying value. Emera performs its
annual impairment test as at March 31.
Impairment assessments are based on fair market value assessments. Fair
market value is determined by use of net present value financial models that
incorporate management's assumptions about future profitability. There was no
impairment provision required in 2006 or 2005.
Changes in Accounting Policies
In 2006, the company adopted the new accounting guideline related to
conditional asset retirement obligations. In addition, Nova Scotia Power
changed its methodology for inventory valuation.
Conditional Asset Retirement Obligations
In December 2005, the Canadian Institute of Chartered Accountants ("CICA")
issued Emerging Issues Committee Abstract 159 Conditional Asset Retirement
Obligations ("EIC-159"). EIC-159 is to be applied retroactively, with
restatement of prior periods, to financial statements for interim and annual
reporting periods ending after March 31, 2006. EIC-159 was issued in response
to the diverse accounting practices that have developed with respect to the
timing of liability recognition when the timing and/or method of settlement
are conditional on a future event.
As a result of adopting EIC-159, the company has determined that it has
conditional asset retirement obligations related to the disposal of
polychlorinated biphenyls ("PCBs"). As at December 31, 2006, property, plant
and equipment has increased by $0.5 million (2005 - $0.6 million), accumulated
depreciation has decreased by $2.0 million (2005 - $1.8 million), and asset
retirement obligations have increased by $2.5 million (2005 - $2.4 million).
There is no impact to net earnings in 2006 and 2005.
Inventory
In August 2006, Nova Scotia Power changed its method of costing fuel
inventory from the first-in, first-out method to the weighted average cost
method to provide more appropriate information. The change in accounting
policy was approved by the UARB.
The CICA Handbook Section 1506 Accounting Changes requires that changes in
accounting policies be applied retroactively to all prior periods presented
for comparative purposes. Nova Scotia Power applied the change in accounting
policy retroactively but did not restate prior periods as the necessary
adjustments were considered immaterial. The change in accounting policy
resulted in a cumulative adjustment to the opening balance of fuel inventory
in Q3 2006 of $1.0 million. As a result, NSPI decreased inventory by
$1.0 million and increased fuel expense by $1.0 million in Q3 2006.
Future Accounting Policy Changes
The CICA has issued standards 1530 Comprehensive Income, 3855 Financial
Instruments - Recognition and Measurement, and 3865 Hedges, which are
applicable to interim and annual financial statements beginning on or after
October 1, 2006. The company is presently finalizing the effect of the new
standards. The following provides more information on each standard.
Comprehensive Income: As a result of the issued standard, a new item,
accumulated other comprehensive income ("AOCI"), will be recognized in the
shareholders' equity section of the consolidated balance sheets beginning in
2007. AOCI will include 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: As a result of the
new standard, financial assets must be classified as loans and receivables,
held-for-trading, available-for-sale, or held-to-maturity. Financial
liabilities must be classified as either held-for-trading, or other than
held-for-trading. Loans and receivables, held-to-maturity financial assets,
and other than held-for-trading financial liabilities are recognized at
amortized cost. Held-for-trading financial assets and liabilities will be
recognized at fair value with any changes in fair value recognized in net
income. Available-for-sale financial assets will be recognized at fair value
with any changes in fair value recognized in other comprehensive income. There
are provisions to recognize certain available-for-sale financial assets at
cost.
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 must be 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.
Dividends and Payout Ratios
Emera Inc.'s common dividend rate was $0.89 ($0.2225 per quarter) per
common share in 2006 and 2005, representing a payout ratio of approximately
78% for 2006 (2005 - 80%). In January 2007, the Board of Directors approved
the common share dividend of $0.89 per share ($0.2225 per quarter).
Business Risks and Enterprise Risk Management
Risk Management
Significant risk management activities for Emera are overseen by the
Enterprise Risk Management Committee to ensure that risks are appropriately
assessed, monitored and controlled within predetermined risk tolerances
established through Board of Directors approved policies.
The company's risk management activities are focused on those areas that
most significantly impact profitability and quality of earnings. These risks
include, but are not limited to, exposure to commodity prices, foreign
exchange, credit risk, interest rates, and regulatory risk.
Commodity Prices
Substantially all of the company's annual fuel requirement is subject to
fluctuation in commodity market prices, prior to any commodity risk management
activities. NSPI utilizes a portfolio strategy for fuel procurement with a
combination of long, medium, and short-term supply agreements. It also
provides for supply and supplier diversification with credit-worthy
counterparties. The strategy is designed to reduce the effects from market
volatility through agreements with staggered expiration dates, volume options,
and varied pricing mechanisms.
Coal/Petroleum Coke
A substantial portion of the company's coal and petroleum coke supply
comes from international suppliers at prevailing market prices. The company
has entered into fixed-price contractual arrangements with several suppliers
as part of the fuel procurement portfolio strategy. Physical contracts are
used to hedge coal price risk due to the lack of liquidity in the financial
markets for coal. The approximate percentage of coal and petcoke requirements
contracted at December 31, 2006 is as follows:
- 2007 - 95%
- 2008 - 50%
- 2009 - 30%
- 2010 - 10%
Heavy Fuel Oil
NSPI manages exposure to changes in the market price of heavy fuel oil
through the use of swaps, options, and futures contracts. The approximate
percentage of heavy fuel oil requirements hedged and contracted as at December
31, 2006 is as follows:
- 2007 - 100%
- 2008 - 35%
- 2009 - 5%
Natural Gas
NSPI has entered into multi-year contracts to purchase approximately
61,600 mmbtu of natural gas per day. Volumes exposed to market prices are
managed using financial instruments where the fuel is required for NSPI's
generation; and the balance is sold against market prices where available for
resale. Fixed price gas volumes not required for generation will be resold
into the gas market with the margin managed using financial instruments. As at
December 31, 2006, amounts of natural gas volumes that have been economically
and/or financially hedged and contracted are approximately as follows:
Natural gas burn:
- 2007 - 95%
- 2008 - 35%
- 2009 - 30%
- 2010 - 30%
Natural gas resale:
- 2007 - 95%
- 2008 - 70%
- 2009 - 65%
- 2010 - 65%
Fuel Mix
The ability to switch fuel provides a dynamic and effective option in
managing commodity price and supply risk.
Foreign Exchange
The risk due to fluctuation of the Canadian dollar against the US dollar
for the cost of fuel is measured and managed. In 2007, NSPI expects
approximately 80% of its anticipated net fuel costs to be denominated in
US dollars; USD from sales of surplus natural gas will provide a natural hedge
against a portion of USD fuel costs. Forward contracts are used to manage the
exposure to fluctuating USD exchange rates. Forward contracts are in place for
over 95% of 2007 anticipated USD net fuel costs. Forward contracts to buy
US $815.4 million over 2007 to 2010 at a weighted average rate of CAD $1.1374
were outstanding at December 31, 2006. Forward contracts to sell
US $66.2 million in 2007 at a weighted average rate of CAD $1.1404 were
outstanding at December 31, 2006.
Interest Rates
Emera manages interest rate risk through a combination of fixed and
floating borrowing and a hedging program. Prior to hedging, floating-rate debt
is estimated to represent approximately 14% of total debt in 2007. Interest
rate caps are used to limit exposure to movements of interest rates on
floating debt. For 2007, interest on approximately 86% of floating debt is
capped at a weighted-average rate of 4.75%.
Credit Risk
Credit risk arising as a result of contractual obligations between the
corporation and other counterparties is managed by assessing the
counterparties' financial creditworthiness prior to assigning credit limits
based on the Board of Directors' approved credit policies. The company
frequently uses collateral agreements within its negotiated master agreements
to further mitigate credit exposure.
Regulatory Risk
Nova Scotia Power
NSPI faces risk with respect to the timeliness and certainty of full
recovery of costs, particularly fuel costs in light of their magnitude and
volatility. A central provision of the approved settlement agreement following
the 2007 rate application is an agreement in principle that the UARB should
establish a fuel adjustment mechanism for Nova Scotia Power to ensure actual
fuel costs are recovered from customers. Hearings on this subject are expected
in mid-2007.
During 2006 the Province of Nova Scotia proposed, and later passed,
regulations under the Electricity Act that set out future requirements for
energy from renewable sources. The regulations require NSPI to meet targets
for an additional 5% of energy from renewable sources in 2010, and a further
5% in 2013. In December NSPI announced solicitation for 130 MW of renewable
energy capacity, which represents a significant portion of the energy required
during the first target period.
The government has also passed Wholesale Market Rules regulation, which
allows NSPI's six municipal utilities to purchase electricity, including
renewable energy, directly from suppliers. The Province continues to assess
measures that would enable the sale of renewable energy directly from power
purchasers to retail customers. The changes reflect policy directions set out
in the Nova Scotia Energy Strategy of 2001. NSPI continues to work closely
with government to ensure that changes in the electricity do not negatively
affect customers or the utility.
Bangor Hydro
Bangor Hydro's business consists of four primary components which are each
governed by their own regulatory structure. The components include
distribution, transmission, stranded costs, and supply (metering, billing, and
settlement).
BHE's distribution business operates under an Alternate Rate Plan, which
is in place until December, 2007. The ARP requires BHE to decrease rates each
year by an assumed productivity increase of approximately 2.5% per year. As
part of the ARP, a penalty is triggered if BHE does not meet certain specified
service quality indices. Under the current ARP, BHE does not have any recourse
to the MPUC should costs rise faster than revenues. However, the ARP does
provide BHE with the potential opportunity to earn a higher return on equity
than under a more traditional cost-of-service regulatory structure. In Q4 2006
BHE announced its intention to file a request for changes in both its
distribution rates and stranded cost rates, to go into effect Q1 2008. Bangor
Hydro's filing requests an increase in distribution rates as a result of
shrinkage in overall load. The increase is substantially offset by a requested
reduction in stranded cost rates.
The transmission business of BHE is primarily regulated by the FERC. The
rates charged are determined by formula and driven by the annual report to the
FERC. Bangor Hydro is a participating transmission owner within the Regional
Transmission Organization for New England, and its operations are therefore
linked with the transmission operations of all of New England. BHE's return on
equity on its transmission assets, and the extent to which BHE will receive
added incentives on the ROE for its transmission assets is determined by FERC
along with the regional transmission owners.
BHE also has the ability to recover stranded costs of both regulatory
assets and the ongoing costs of both regulatory assets and purchasing power at
above-market prices. This ability eliminates the commodity risk involved with
fixed price contracts. As mentioned previously, BHE has filed a request for a
decrease in stranded cost rates effective Q1 2008.
Metering, billing and settlement services for power suppliers are provided
directly by BHE within its service territory, and BHE is permitted to recover
all prudently incurred costs for these services.
Labour
In June 2004, Nova Scotia Power reached a fifty-two month agreement with
800 unionized employees which expires in the middle of 2007.
Bangor Hydro's contract with its unionized employees expired at the end of
2005 and a new agreement has been reached, which will expire in June 2010.
Environmental Protection
Corporate Environmental Governance
Emera is committed to operating in a manner that is respectful and
protective of the environment, and in full compliance with legal requirements
and company policy. Emera and its wholly-owned subsidiaries have implemented
this policy through development and application of environmental management
systems ("EMS").
Implementation of EMS has provided a systematic focus on environmental
issues such that risks are identified and managed proactively. All areas of
Emera undertook initiatives in 2006 to reduce potential environmental risks
and associated costs.
Conformance with legislative and company requirements is verified through
an environmental audit program. There were no significant environmental or
regulatory compliance issues identified during the 2006 audits. Plans are in
place to promptly address any audit finding and continually improve the
environmental management of the operations.
Oversight of environmental matters is carried out by the NSPI Board of
Directors' Environmental, Safety and Security Committee as well as the Boards
of all other Emera operating companies. In addition, an Environmental Council,
made up of senior Emera employees with working accountability for environment,
continues to guide the implementation of programs that address key
environmental issues.
Climate Change and Air Emissions
In October 2006 the federal government released a notice of intent to
regulate air emissions and greenhouse gases under Bill C-30, Canada's Clean
Air Act. The notice proposes to establish targets for air emissions consistent
with standards that are substantially analogous to those in the US. It also
proposes to establish targets for greenhouse gases that would reduce
greenhouse gas emissions in the short term, beyond those proposed in 2005. The
proposal would also achieve long term reductions of greenhouse gases of
between 45-65% from 2003 levels by 2050. Company staff continues to work with
the federal and provincial governments to develop rules that consider the
potential costs and benefits to the company and its customers.
In 2006, NSPI continued to comply with annual provincial emissions limits.
Plans have been developed to achieve the objectives in NSPI's Air Emissions
Strategy, which addresses the entire suite of emissions including those linked
to greenhouse gases. In 2006, NSPI:
- Invested approximately $4 million to reduce oxides of nitrogen (NOx)
from the Lingan plant,
- Continued to engage stakeholders and is working to develop an
Integrated Resource Plan that utilizes supply-side management and
demand-side options, to enable NSPI to meet future emissions and other
requirements in a cost-effective and reliable manner,
- Worked with independent power producers to increase NSPI's renewable
energy supply by over 60 MW, almost entirely from wind, with some
biomass/landfill gas,
- In early February 2007, NSP provided notice that the company plans to
issue a request for proposal for an additional 130 MWh of new renewable
energy supply, and
- Continued efforts to advance research into clean energy sources and
carbon dioxide storage including the submission of an application for
government funding to assist in establishing a stream tidal energy
demonstration project off the coast of Nova Scotia.
Summary of Quarterly Reports
For the quarter ended
millions of dollars (except earnings per common share)
-------------------------------------------------------------------------
Q4 Q3 Q2 Q1
2006 2006 2006 2006
-------------------------------------------------------------------------
Total revenues $ 307.0 $ 272.4 $ 275.9 $ 310.7
-------------------------------------------------------------------------
Net earnings from continuing
operations $ 33.5 $ 19.5 $ 29.2 $ 43.6
-------------------------------------------------------------------------
Net earnings applicable to
common shares $ 33.5 $ 19.5 $ 29.2 $ 43.6
-------------------------------------------------------------------------
Earnings per common share
- basic:
Continuing operations $ 0.30 $ 0.18 $ 0.26 $ 0.40
Discontinued operations - - - -
-------------------------------------------------------------------------
$ 0.30 $ 0.18 $ 0.26 $ 0.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share
- diluted:
Continuing operations $ 0.30 $ 0.18 $ 0.26 $ 0.38
Discontinued operations - - - -
-------------------------------------------------------------------------
$ 0.30 $ 0.18 $ 0.26 $ 0.38
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q4 Q3 Q2 Q1
2005 2005 2005 2005
-------------------------------------------------------------------------
Total revenues $ 297.1 $ 281.1 $ 280.1 $ 309.7
-------------------------------------------------------------------------
Net earnings from continuing
operations $ 37.7 $ 18.1 $ 19.1 $ 47.2
-------------------------------------------------------------------------
Net earnings applicable to
common shares $ 37.7 $ 15.9 $ 19.3 $ 48.3
-------------------------------------------------------------------------
Earnings per common share
- basic:
Continuing operations $ 0.34 $ 0.16 $ 0.18 $ 0.43
Discontinued operations - (0.02) - 0.01
-------------------------------------------------------------------------
$ 0.34 $ 0.14 $ 0.18 $ 0.44
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share
- diluted:
Continuing operations $ 0.34 $ 0.16 $ 0.18 $ 0.41
Discontinued operations - (0.02) - 0.01
-------------------------------------------------------------------------
$ 0.34 $ 0.14 $ 0.18 $ 0.42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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.
EMERA INC.
Consolidated Financial Statements
December 31, 2006 and 2005
MANAGEMENT REPORT
Management's Responsibility for Financial Reporting
The accompanying consolidated financial statements of Emera Inc. ("Emera")
and the information in this annual report are the responsibility of management
and have been approved by the Board of Directors ("Board").
The consolidated financial statements have been prepared by management in
accordance with Canadian generally accepted accounting principles. When
alternative accounting methods exist, management has chosen those it deems
most appropriate in the circumstances. Nova Scotia Power Inc. ("NSPI"), one of
Emera's wholly-owned electric utilities and principal subsidiary, is regulated
by the Nova Scotia Utility and Review Board, which also examines and approves
NSPI's accounting policies and practices. Emera's other wholly-owned electric
utility and subsidiary, Bangor Hydro-Electric Company ("Bangor Hydro"), is
regulated by the Federal Energy Regulatory Commission and the Maine Public
Utilities Commission, which also examine and approve Bangor Hydro's accounting
policies and practices. In preparation of these consolidated financial
statements, estimates are sometimes necessary when transactions affecting the
current accounting period cannot be finalized with certainty until future
periods. Management believes that such estimates, which have been properly
reflected in the accompanying consolidated financial statements, are based on
careful judgements and are within reasonable limits of materiality. Management
has determined such amounts on a reasonable basis in order to ensure that the
consolidated financial statements are presented fairly in all material
respects. Management has prepared the financial information presented
elsewhere in the annual report and has ensured that it is consistent with that
in the consolidated financial statements.
Emera maintains effective systems of internal accounting and
administrative controls, consistent with reasonable cost. Such systems are
designed to provide reasonable assurance that the financial information is
relevant, reliable and accurate and that Emera's assets are appropriately
accounted for and adequately safeguarded.
The Board is responsible for ensuring that management fulfils its
responsibilities for financial reporting and is ultimately responsible for
reviewing and approving the consolidated financial statements. The Board
carries out this responsibility principally through its Audit Committee.
The Audit Committee is appointed by the Board, and its members are
directors who are not officers or employees of Emera. The Audit Committee
meets periodically with management, as well as with the internal auditors and
with the external auditors, to discuss internal controls over the financial
reporting process, auditing matters and financial reporting issues, to satisfy
itself that each party is properly discharging its responsibilities, and to
review the annual report, the consolidated financial statements and the
external auditors' report. The Audit Committee reports its findings to the
Board for consideration when approving the consolidated financial statements
for issuance to the shareholders. The Audit Committee also considers, for
review by the Board and approval by the shareholders, the appointment of the
external auditors.
The consolidated financial statements have been audited by Ernst & Young
LLP, the external auditors, in accordance with Canadian generally accepted
auditing standards. Ernst & Young LLP has full and free access to the Audit
Committee.
February 5, 2007
"Christopher Huskilson" "Nancy Tower, FCA"
President and Chief Executive Officer Chief Financial Officer
AUDITORS' REPORT
To the Shareholders of Emera Inc.
We have audited the consolidated balance sheets of Emera Inc. as at
December 31, 2006 and 2005, and the consolidated statements of earnings,
retained earnings and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Canadian generally accepted
auditing standards. Those standards require that we plan and perform an audit
to obtain reasonable assurance whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2006 and
2005 and the results of its operations and its cash flows for the years then
ended in accordance with Canadian generally accepted accounting principles.
Halifax, Canada
February 5, 2007
"Ernst & Young LLP"
Chartered Accountants
Emera Inc.
Consolidated Statements of Earnings
Year Ended December 31
millions of dollars (except earnings per common share) 2006 2005
-------------------------------------------------------------------------
Revenue
Electric $1,132.0 $1,125.9
Other 34.0 42.1
-------------------------------------------------------------------------
1,166.0 1,168.0
-------------------------------------------------------------------------
Cost of operations
Fuel for generation and purchased power 347.7 432.0
Operating, maintenance and general 255.6 248.2
Provincial, state, and municipal taxes 48.0 48.4
Provincial tax deferral (note 13) - (4.5)
Depreciation 145.2 136.1
Regulatory amortization 22.8 19.4
Allowance for funds used during construction (5.8) (4.4)
-------------------------------------------------------------------------
813.5 875.2
-------------------------------------------------------------------------
Earnings from operations 352.5 292.8
Equity earnings (note 6) 4.9 6.5
-------------------------------------------------------------------------
Earnings before interest and income taxes 357.4 299.3
Interest (note 7) 127.1 117.4
Amortization of defeasance costs 12.7 13.2
Other income (note 8) (8.9) (8.0)
-------------------------------------------------------------------------
Earnings before income taxes 226.5 176.7
Income taxes (note 9) 87.4 53.5
Income taxes deferral (note 13) - (12.2)
-------------------------------------------------------------------------
Net earnings before non-controlling interest 139.1 135.4
Non-controlling interest (note 10) 13.3 13.3
-------------------------------------------------------------------------
Net earnings from continuing operations 125.8 122.1
Loss from discontinued operations, net of tax
(note 16) - (0.9)
-------------------------------------------------------------------------
Net earnings applicable to common shares $ 125.8 $ 121.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - basic (note 11)
Continued operations $ 1.14 $ 1.12
Discontinued operations - (0.01)
-------------------------------------------------------------------------
$ 1.14 $ 1.11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - diluted (note 11)
Continued operations $ 1.12 $ 1.10
Discontinued operations - (0.01)
-------------------------------------------------------------------------
$ 1.12 $ 1.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Emera Inc.
Consolidated Statements of Retained Earnings
Year Ended December 31
millions of dollars 2006 2005
-------------------------------------------------------------------------
Retained earnings, beginning of year $ 423.4 $ 399.6
Net earnings applicable to common shares 125.8 121.2
-------------------------------------------------------------------------
549.2 520.8
Dividends 98.3 97.4
-------------------------------------------------------------------------
Retained earnings, end of year $ 450.9 $ 423.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Emera Inc.
Consolidated Balance Sheets
As at December 31
2006 2005
Restated
millions of dollars (note 2)
-------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 7.6 $ 21.5
Restricted cash 11.9 5.8
Accounts receivable (note 12) 253.6 231.8
Income tax receivable 5.3 15.1
Inventory (note 2) 113.6 76.1
Prepaid expenses 53.9 15.9
Future income tax assets (note 9) 18.9 9.3
Energy marketing assets 37.3 16.0
-------------------------------------------------------------------------
502.1 391.5
-------------------------------------------------------------------------
Long-term receivables (note 12) - 48.4
-------------------------------------------------------------------------
Energy marketing assets 2.0 4.1
-------------------------------------------------------------------------
Deferred charges (note 13) 465.4 510.2
-------------------------------------------------------------------------
Future income tax assets (note 9) 10.0 19.0
-------------------------------------------------------------------------
Goodwill (note 18) 97.1 97.1
-------------------------------------------------------------------------
Investments (note 6) 101.3 99.1
-------------------------------------------------------------------------
Property, plant & equipment (note 14) 2,756.4 2,789.2
Construction work in progress 125.5 40.0
-------------------------------------------------------------------------
2,881.9 2,829.2
-------------------------------------------------------------------------
$4,059.8 $3,998.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Current portion of long-term debt (note 21) $ 3.4 $ 152.9
Short-term debt (note 20) 133.2 88.1
Accounts payable and accrued charges 286.0 248.6
Income tax payable 39.3 1.5
Dividends payable 3.2 3.2
Energy marketing liabilities 36.7 12.1
-------------------------------------------------------------------------
501.8 506.4
-------------------------------------------------------------------------
Energy marketing liabilities 1.4 2.9
-------------------------------------------------------------------------
Future income tax liabilities (note 9) 86.2 78.9
-------------------------------------------------------------------------
Asset retirement obligations (note 2 and note 19) 78.1 74.1
-------------------------------------------------------------------------
Deferred credits (note 13) 66.1 77.5
-------------------------------------------------------------------------
Long-term debt (note 21) 1,657.4 1,631.8
-------------------------------------------------------------------------
Non-controlling interest (note 10) 260.7 260.8
-------------------------------------------------------------------------
Shareholders' equity
Common shares (note 22) 1,055.2 1,039.2
Contributed surplus (note 23) 2.2 1.8
Foreign exchange translation adjustment (note 25) (100.2) (98.2)
Retained earnings 450.9 423.4
-------------------------------------------------------------------------
1,408.1 1,366.2
-------------------------------------------------------------------------
$4,059.8 $3,998.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contingencies (note 27)
Commitments (notes 5, 24 and 28)
Guarantees (note 29)
See accompanying notes to the consolidated financial statements.
Approved on behalf of the Board of Directors
"Derek Oland" "Christopher Huskilson"
Chairman President and Chief Executive Officer
Emera Inc.
Consolidated Statements of Cash Flows
Year Ended December 31
millions of dollars 2006 2005
-------------------------------------------------------------------------
Operating activities
Net earnings before non-controlling interest $ 139.1 $ 135.4
Non-cash items:
Depreciation 145.2 136.1
Deferral of provincial taxes and income taxes
(note 13) - (16.7)
Amortization of deferred charges 13.9 15.6
Equity earnings (4.9) (6.5)
Regulatory amortization 22.8 19.4
Allowance for funds used during construction (5.8) (4.4)
Future income taxes 5.1 3.3
Post-retirement benefits 8.9 (5.0)
Other non-cash operating items (1.2) (6.1)
Discontinued operations - 1.2
Other cash operating items 3.4 4.9
-------------------------------------------------------------------------
326.5 277.2
Change in non-cash operating working capital 19.3 (112.9)
-------------------------------------------------------------------------
Net cash provided by operating activities 345.8 164.3
-------------------------------------------------------------------------
Investing activities
Property, plant and equipment (193.7) (129.3)
(Increase) decrease in restricted cash (6.1) 11.9
Retirement spending net of salvage (3.2) (4.7)
Proceeds on disposition (note 16) - 18.4
Investments - 41.7
Acquisition (note 15) - (55.2)
-------------------------------------------------------------------------
Net cash used in investing activities (203.0) (117.2)
-------------------------------------------------------------------------
Financing activities
Retirements of long-term debt (112.6) (126.7)
Issuance of long-term debt - 275.9
Increase (decrease) in short-term debt 30.5 (143.7)
Issuance of common shares 15.3 20.9
Dividends on common shares (98.3) (97.4)
Dividends paid by subsidiaries to
non-controlling interest (13.3) (14.1)
Long-term financing of asset sale 20.0 15.0
Other financing activities 1.7 1.8
-------------------------------------------------------------------------
Net cash used in financing activities (156.7) (68.3)
-------------------------------------------------------------------------
Decrease in cash and cash equivalents (13.9) (21.2)
Cash and cash equivalents, beginning of year 21.5 42.7
-------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 7.6 $ 21.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents consists of:
Cash $ 7.2 $ 6.9
Short-term investments 0.4 14.6
-------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 7.6 $ 21.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental disclosure of cash paid:
Interest $ 123.9 $ 120.7
Income and capital taxes $ 45.7 $ 61.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Emera Inc.
Notes to the Consolidated Financial Statements
December 31, 2006 and 2005
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Emera Inc. ("Emera" or the "Company"), incorporated in the Province of
Nova Scotia, through its principal subsidiaries, Nova Scotia Power Inc. ("Nova
Scotia Power" or "NSPI") and Bangor Hydro-Electric Company ("Bangor Hydro" or
"BHE"), is engaged in the production and sale of electric energy.
Nova Scotia Power is the primary electricity supplier in Nova Scotia
providing over 95% of electricity generation, transmission and distribution in
the province. NSPI is a public utility as defined under the Public Utilities
Act of Nova Scotia ("Act") and is subject to regulation under the Act by the
Utility and Review Board ("UARB"). The Act gives the UARB authority over
NSPI's operations and expenditures. Electricity rates for NSPI's customers are
subject to UARB approval. NSPI is not subject to an annual rate review
process, but rather participates in hearings from time to time at NSPI's or
the regulator's request.
NSPI is regulated under a cost of service model, with rates set to cover
prudently incurred costs of providing electricity service to customers, and
provide an opportunity to earn an appropriate return to investors. NSPI's
return on equity ("ROE") range is 9.3% to 9.8%, on a maximum allowed common
equity component of 40% of the total capitalization. Rates were last set using
9.55% ROE with a common equity component of 37.5%.
NSPI's accounting policies are subject to examination and approval by the
UARB.
Bangor Hydro's core business is the transmission and distribution ("T&D")
of electricity. Electricity is deregulated in Maine, and several suppliers
compete to provide customers with the commodity that is delivered through the
BHE T&D network. In addition to the T&D network, BHE has substantial net
regulatory assets (stranded costs), which arose through the electricity
industry restructuring, and as a result of rate and accounting orders issued
by its regulators. Approximately 55% of BHE's electric rates represent
distribution services, 15% relate to stranded costs recoveries, and 30% to
transmission service. The rates for each element are established in distinct
regulatory proceedings. The transmission operations are regulated by the
Federal Energy Regulatory Commission ("FERC"), and the distribution operations
and stranded costs are regulated by the Maine Public Utilities Commission
("MPUC").
For distribution services, BHE operates under an Alternate Rate Plan
("ARP"), which provides for an earnings band of 5% to 17% return on equity on
distribution operations, with rates set at the midpoint of 11%. There is a
50/50 sharing mechanism between BHE and customers outside of the earnings
band. The ARP also includes performance standards and provides for average
annual reductions in distribution rates of approximately 2.5% for five years,
to 2007.
The MPUC provides an allowed return on equity of 10% on BHE's stranded
assets. BHE is required to hold stranded cost proceedings at least every three
years to adjust any substantial differences in stranded cost estimates from
prior periods that may arise because of differences between forecast and sales
volume or the output of facilities subject to purchase power agreements.
Transmission rates are set by the FERC annually on July 1, based on the
prior year's revenue requirement. The allowed ROE for transmission operations
was 11.25% through October 31, 2006. As a result of a recent FERC ruling, the
allowed ROE on transmission investments ranges from 10.9% for low voltage
transmission up to 12.4% for high voltage transmission developed as a result
of the regional system plan, which includes the NRI project.
Bangor Hydro's accounting policies are subject to examination and approval
by FERC and the MPUC.
Emera follows Canadian generally accepted accounting principles ("GAAP").
The accounting policies approved by the regulators of NSPI and Bangor Hydro
may differ from GAAP for non rate-regulated companies in that the timing of
recognition of certain revenues and expenses in these operations may differ
from that otherwise expected under GAAP. Where the differences between GAAP
and GAAP for rate-regulated companies are considered significant, disclosure
of the policy has been made in these notes to the consolidated financial
statements.
a. Consolidation
The consolidated financial statements include the accounts of
Emera Inc. and its subsidiaries. Intercompany transactions and
accounts have been eliminated.
b. Measurement Uncertainty
The preparation of financial statements in accordance with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting periods.
At the end of each month, amounts of energy delivered to customers
since the date of their last meter reading are estimated along with
the associated unbilled revenues. This estimate is based on several
different factors including generation, estimated usage by customer
class, weather and line losses.
Actual results may differ from these estimates.
c. Revenue Recognition
The Company's revenue recognition policy is as follows:
- Electric: Revenues are recognized on the accrual basis, which
includes an estimate of electricity consumed by customers in the
year but billed subsequent to year-end.
- Energy Marketing: Derivative financial and commodity instruments
that are not entered into for hedging purposes are recognized at
fair market value at year-end.
- Other: Revenues are recognized on the accrual basis, which includes
an estimate for services performed and goods delivered during the
year but billed subsequent to year-end.
- Unearned revenue is recorded as a deferred credit.
Accounting for the impact of rate regulation:
Electric revenues generated by NSPI and Bangor Hydro are recognized at
rates set by their respective regulators. The Company is unable to
determine the effect on electric revenue in the absence of regulation.
d. Allowance for Funds Used during Construction
Accounting for the impact of rate regulation:
In accordance with accounting policies determined by their respective
regulators, NSPI and Bangor Hydro provide for the cost of financing
construction work in progress by including an allowance for funds used
during construction ("AFUDC") as an addition to the cost of property
constructed, using a weighted average cost-of-capital. AFUDC is
included in property, plant and equipment and construction work in
progress for financial reporting purposes and is charged to operations
through depreciation over the service life of the related assets and
recovered through future revenues. Since AFUDC includes not only an
interest component, but also an equity component, it exceeds the
amount that could be capitalized in the absence of the regulated
accounting policies.
e. Regulatory Amortization
Accounting for the impact of rate regulation:
In accordance with the regulations of the UARB, significant assets of
Nova Scotia Power, which are not currently being used and are not
expected to provide service to customers in the foreseeable future,
are amortized over five years. In 2000 the UARB approved NSPI's
request to amortize the Glace Bay generating station over five years.
The UARB had allowed Nova Scotia Power flexibility in determining the
annual amount to be written off in order to support rate stability. On
July 28, 2003, the UARB approved the Company's request to extend the
write-off period through 2008, if necessary, with an annual minimum
amortization of $6.2 million. The unamortized portion of the
generation station is included in property, plant and equipment. In
the absence of the UARB's approved accounting policies, the generation
station would have been written off in the year when NSPI determined
that the unamortized cost of the generating station would not be
recoverable. More details are provided in note 14.
In accordance with rate and accounting orders issued by the MPUC,
Bangor Hydro has recorded regulatory assets and liabilities on its
balance sheet. These regulatory assets and liabilities are being
amortized over varying lives expiring through to 2018 through charges
to earnings. These regulatory assets and liabilities are included in
deferred assets and deferred liabilities and include costs related to
terminating/restructuring purchased power contracts, the Seabrook
nuclear project, decommissioning costs for Maine Yankee, obligations
to Hydro-Quebec, and the stranded cost revenue requirement levelizer,
and are described in more detail in note 13.
f. Property, Plant and Equipment
Property, plant and equipment are recorded at original cost, net of
contributions in aid of construction. When property, plant and
equipment are replaced or retired, any remaining net book value is
charged to net earnings.
Depreciation is determined by the straight-line method, based on the
estimated remaining service lives of the depreciable assets in each
category. The estimated average service life for the Company's
unregulated general assets is 6 years (2005 - 11 years). Unregulated
generation assets have an estimated average service life of 51 years
(2005 - 51 years).
When indicators of impairment exist, the Company determines whether
the net carrying amount of property, plant and equipment is
recoverable from future undiscounted cash flows. Factors, which could
indicate impairment exists, include significant changes in regulation,
a change in the Company's strategy or underperformance relative to
projected future operating results.
Accounting for the impact of rate regulation:
During 2003, following completion of a depreciation study, and a
negotiated agreement with stakeholders, NSPI's regulator approved new
depreciation rates which were to be phased in over four years
beginning in 2004. In the decision on NSPI's 2005 rate application,
the UARB delayed the phase-in of year two rates for one year. In the
decision on NSPI's 2006 rate application, the UARB approved restarting
of the phase-in including year-two in 2006 rates. In its February 5,
2007 decision, the UARB postponed the scheduled year-three phase-in of
increased depreciation rates until the next rate application. Absent
consideration of growth in plant-in-service, the phase-in of new
depreciation rates will increase depreciation expense by approximately
$5 million per year for a cumulative increase of $20 million over the
four-year period. In the absence of the UARB's approval of
depreciation rates, NSPI would be required to set rates based on
management's best estimates of useful lives. The average rates for the
major categories of plant in service are summarized as follows:
Function 2006 2005
----------------------------------------------------------------------
Generation
Thermal 2.44% 2.38%
Gas turbines 2.32% 2.18%
Combustion turbines 3.33% 3.33%
Hydroelectric 1.39% 1.26%
Wind turbines 5.00% 5.00%
Transmission 2.65% 2.68%
Distribution 4.04% 3.96%
General plant 6.55% 5.62%
General plant under capital lease 11.97% 9.50%
Weighted average depreciation rate 3.06% 2.93%
----------------------------------------------------------------------
Bangor Hydro's depreciation is determined by the straight-line method,
based on the estimated service lives of the depreciable assets in each
category. In 2004 BHE implemented the results of a depreciation study
that was completed in 2004 and approved by its regulators. The
estimated average service lives in years for the major categories of
plant in service are summarized as follows:
Function 2006 2005
----------------------------------------------------------------------
Transmission 45 43
Distribution 35 36
Other 17 16
Weighted average service life 33 32
----------------------------------------------------------------------
In accordance with regulator approved accounting policies, when
depreciable property, plant and equipment of NSPI and Bangor Hydro are
replaced or retired, the original cost plus any removal costs incurred
(net of salvage) are charged to accumulated depreciation with no gain
or loss reflected in results of operations. Gains and losses will be
charged to results of operation in the future through adjustments to
depreciation expense. In the absence of regulator approved accounting
policies, gains and losses on the disposition of property, plant and
equipment are charged to net earnings as incurred.
g. Capitalization policy
Capital assets of Nova Scotia Power and Bangor Hydro include labour,
inventories, and other non-labour costs directly attributable to the
capital activity. In addition, in order to ensure the full cost
approach, overhead costs that contribute to the capital program are
allocated to capital projects. These costs include corporate costs
such as finance, information technology, executive and other support
functions, and employee benefits, insurance, inventory costs, and
fleet operating and maintenance costs. Nova Scotia Power and Bangor
Hydro calculate an application rate and only eligible operating
expenditures are used in the calculation. NSPI and BHE apply overhead
costs based on direct labour costs. The application rate varies
depending on the type of capital expenditure. In addition, BHE applies
inventory overhead based on inventory issued to the project, and
applies general and administrative overhead based upon non-labour
charges.
h. Leases
Leases that substantially transfer all the benefits and risks of
ownership of property, plant and equipment to the Company, or
otherwise meet the criteria for capitalizing a lease under GAAP, are
accounted for as capital leases. An asset is recognized at the time a
capital lease is entered into together with its related long-term
obligation. Property, plant and equipment recognized under capital
leases are depreciated on the same basis as described in Note 1(f).
Payments on operating leases are expensed as incurred.
i. Income Taxes and Investment Tax Credits
Emera follows the future income tax method of accounting for income
taxes.
Investment tax credits arise as a result of incurring qualifying
scientific research and development expenditures and are recorded in
the year as a reduction from the related expenditures where there is
reasonable assurance of collection.
Accounting for the impact of rate regulation:
In accordance with ratemaking regulations established by the UARB,
NSPI uses the taxes-payable method of accounting for income taxes.
Bangor Hydro uses the future income tax method where allowed for
ratemaking purposes. NSPI and Bangor Hydro would be required to
recognize all future income tax assets and liabilities in the absence
of their regulator approved accounting policies. More details are
provided in note 9.
j. Employee Future Benefits
Pension obligations, and obligations associated with non-pension
post-retirement benefits such as health benefits to retirees and
retirement awards, are actuarially determined using the projected
benefit method prorated on services and management's best estimate
assumptions. The accrued benefit obligation is valued based on market
interest rates at the valuation date.
Pension fund asset values are calculated using market values at year-
end. The expected return on pension assets is determined based on
market-related values. The market-related values are determined in a
rational and systematic manner so as to recognize investment gains and
losses, relative to the assumed rate of return, over a five-year
period.
Adjustments to the accrued benefit obligation arising from plan
amendments are amortized on a straight-line basis over the expected
years of future service to the full eligibility date for active
employees.
For any given year, when NSPI's net actuarial gain (loss), less the
actuarial gain (loss) not yet included in the market-related value of
plan assets, exceeds 10% of the greater of the accrued benefit
obligation and the market-related value of the plan assets, an amount
equal to the excess divided by the average remaining service period
("ARSP") is amortized on a straight-line basis. For NSPI, the ARSP of
the active employees is 10 years as at December 31, 2006 (2005 - 10
years). For Bangor Hydro this excess is amortized on a straight-line
basis over the expected ARSP, in accordance with ratemaking purposes,
which is 12 years as at December 31, 2006 (2005 - 13 years).
On January 1, 2000 Emera adopted the new accounting standard on
employee future benefits using the prospective application method. The
transitional obligation (asset) resulting from the initial application
is amortized linearly over 13 years, which was the expected ARSP of
active employees at the transition date.
The difference between benefit cost and pension funding is recorded as
a deferred asset or credit on the balance sheet.
k. Share-Based Compensation
The Company has several share-based compensation plans, which are a
common share option plan for senior management, an employee common
share purchase plan, a deferred share unit plan, and a restricted
share unit plan. The Company accounts for its plans in accordance with
the fair value based method of accounting for share-based
compensation.
l. Cash and Cash Equivalents
Short-term investments, which consists of money market instruments
with maturities of three months or less, are considered to be cash
equivalents and are recorded at cost, which approximates current
market value. The short-term investments have an effective interest
rate of 5.23% at December 31, 2006 (2005 - 3.53%).
m. Inventory
Inventories of materials and supplies are valued at the lower of
average cost and market. Fuel inventory is valued at the lower of the
weighted average cost method, and net realizable value.
n. Debt Financing Costs
Financing costs pertaining to debt issues are amortized over the life
of the related debt.
o. Derivative Financial & Commodity Instruments
The Company uses various derivative financial instruments to hedge its
exposure to foreign exchange, interest rate, and commodity price
risks. If the documentation and effectiveness requirements are met,
gains and losses on these instruments are deferred and recognized in
earnings in the same period the related hedged risk is realized
(settlement accounting). Where documentation and effectiveness
requirements are not met, the instruments are marked-to-market in the
period of ineffectiveness with an adjustment to earnings.
If a hedging relationship is terminated, gains and losses on the
instruments up until the date of termination are deferred and
recognized in the same period the related hedged risk is realized. The
instruments, if retained, would then be marked-to-market from the
termination date on.
Amounts received or paid related to instruments used to hedge foreign
exchange and commodity price risks are recognized in the cost of fuel
purchases. Amounts received or paid, including any gains and losses on
instruments used to hedge interest rate risks, are recognized over the
term of the hedged item in interest expense. The derivatives are not
recorded on the balance sheet. Non-hedging derivative financial and
commodity instruments are entered into and are marked-to-market at
each reporting date and are reflected on the balance sheet as energy
marketing assets or energy marketing liabilities. The net margin
recognized is reflected in other revenue.
Derivative financial and commodity instruments are reflected in
operating activities on the statement of cash flows.
Accounting for the impact of rate regulation:
In the course of implementing the provisions of Accounting Guideline
13 Hedging Relationships ("AcG-13"), NSPI determined that it could not
meet the probability requirement of the standard for its derivative
financial instruments in place to hedge natural gas and heavy fuel oil
for its Tufts Cove generating station. This is due to the generating
station's ability to fuel switch and NSPI's economic dispatch based on
the cost of these two fuels. The UARB has allowed NSPI to apply hedge
accounting to these derivative financial instruments as long as the
other requirements of AcG-13 are met. Absent UARB approval, NSPI would
be required to recognize these derivative financial instruments at
fair value with any resulting changes in fair value recognized in net
earnings.
p. Goodwill
Goodwill represents the excess of the purchase price of an acquired
business over the net amount of the fair values assigned to its assets
and liabilities and is not subject to amortization. The Company
evaluates the carrying value of goodwill for potential impairment
through an annual review and analysis of fair market value. Goodwill
is also evaluated for potential impairment between annual tests if an
event or circumstances occur that more likely than not reduces the
fair value of a business below its carrying value. Fair market value
is determined by use of net present value financial models, which
incorporate management's assumptions of future profitability.
q. Long-Term Investments
The Company accounts for certain investments, over which it shares
control, using the proportionate consolidation method, whereby the
Company recognizes its pro-rata share of the jointly controlled assets
and the liabilities jointly incurred in the Company's balance sheet,
recognizes its pro-rata share of any revenue and expenses in the
Company's statement of earnings, and recognizes its pro-rata share of
cash flows on the Company's statement of cash flows. Emera accounts
for its investments in Bear Swamp and Intragas Energy using
proportionate consolidation.
The Company accounts for certain investments, over which it maintains
significant influence, but not control, using the equity method,
whereby the amount of the investment is adjusted annually for the
Company's pro-rata share of the income or loss of investment and
reduced by the amount of any dividends received. Emera accounts for
its investments in Maritimes & Northeast Pipeline, Maine Yankee Atomic
Power Company, and Maine Electric Power Company Inc. using the equity
method.
Long-term investments over which Emera does not have significant
influence are accounted for on the cost basis.
r. Foreign Currency Translation
Monetary assets and liabilities denominated in foreign currencies are
converted to Canadian dollars at rates of exchange prevailing at the
balance sheet date. The resulting differences between the translation
at the original transaction date and the balance sheet date are
charged to earnings.
Assets and liabilities of self-sustaining foreign operations are
translated using the exchange rates in effect at the balance sheet
date and the results of operations at the average rates for the
period. The resulting exchange gains and losses are deferred and
included in a separate component of shareholders' equity.
s. Research and Development Costs
All research and development costs are expensed in the year incurred
unless they qualify for deferral as a part of capital assets.
2. CHANGE IN ACCOUNTING POLICIES
Conditional Asset Retirement Obligations
In December 2005, the Canadian Institute of Chartered Accountants ("CICA")
issued Emerging Issues Committee Abstract 159 Conditional Asset Retirement
Obligations ("EIC-159"). EIC-159 is to be applied retroactively, with
restatement of prior periods, to financial statements for interim and annual
reporting periods ending after March 31, 2006. EIC-159 was issued in response
to the diverse accounting practices that have developed under CICA Handbook
Section 3110 Asset Retirement Obligations ("Section 3110") with respect to the
timing of liability recognition when the timing and/or method of settlement
are conditional on a future event.
As a result of adopting EIC-159, the Company has determined that it has
conditional asset retirement obligations related to the disposal of
polychlorinated biphenyls ("PCBs"). As at December 31, 2006, property, plant
and equipment has increased by $0.5 million (2005 - $0.6 million), accumulated
depreciation has decreased by $2.0 million (2005 - $1.8 million), and asset
retirement obligations have increased by $2.5 million (2005 - $2.4 million).
There is no impact to net earnings or retained earnings in 2006 and 2005.
Inventory
In August 2006, Nova Scotia Power changed its method of costing fuel
inventory from the first-in, first-out method to the weighted average cost
method to provide more appropriate information. The change in accounting
policy has been approved by the UARB.
The CICA Handbook Section 1506 Accounting Changes requires that changes in
accounting policies be applied retroactively to all prior periods presented
for comparative purposes. Nova Scotia Power applied the change in accounting
policy retroactively but did not restate prior periods as the necessary
adjustments were considered immaterial. The change in accounting policy
resulted in a cumulative adjustment to the opening balance of fuel inventory
in Q3 2006 of $1.0 million. As a result, NSPI decreased inventory by
$1.0 million and increased fuel expense by $1.0 million in Q3 2006.
3. SEGMENT INFORMATION
The Company has two reportable segments: Nova Scotia Power and Bangor
Hydro. The Company evaluates performance based on contribution to consolidated
net earnings applicable to common shareholders. The accounting policies of the
reported segments are the same as those described in the summary of
significant accounting policies.
Reported segments are determined based on Emera's operating activities.
NSPI is engaged in the production and sale of electric energy in Nova Scotia;
and Bangor Hydro is engaged in the transmission and distribution of electric
energy in central Maine. Other revenue is largely generated from energy
marketing margin and electric revenue from the Company's investment in Bear
Swamp.
-------------------------------------------------------------------------
Nova
Scotia Bangor
millions of dollars Power Hydro Other(x) Total
-------------------------------------------------------------------------
Year ended December 31, 2006:
Revenues from external customers $ 977.5 $ 135.0 $ 53.5 $1,166.0
Depreciation 127.8 14.7 2.7 145.2
Cost of operations, including
depreciation 670.4 96.6 46.5 813.5
Equity earnings - - 4.9 4.9
Interest expense 105.4 11.7 10.0 127.1
Other income 8.9 - - 8.9
Income taxes 80.3 10.0 (2.9) 87.4
Net earnings applicable to
common shareholders 104.3 16.8 4.7 125.8
Net inter-segment
revenues/(expenses) 158.6 (3.8) (154.8) -
Capital expenditures 99.0 81.5 13.2 193.7
As at December 31, 2006
Total assets 3,061.5 644.6 353.7 4,059.8
Investments subject to
significant influence - 2.7 95.8 98.5
Goodwill - 97.1 - 97.1
-------------------------------------------------------------------------
Year ended December 31, 2005:
Revenues from external customers 962.8 147.0 58.2 1,168.0
Depreciation 119.5 14.9 1.7 136.1
Cost of operations, including
depreciation 722.1 110.5 42.6 875.2
Equity earnings - - 6.5 6.5
Interest expense 97.9 12.1 7.4 117.4
Other income 8.0 - - 8.0
Income taxes 45.5 9.4 (1.4) 53.5
Net earnings from continuing
operations 91.2 14.9 16.0 122.1
Net earnings applicable to
common shareholders 91.2 14.9 15.1 121.2
Net inter-segment
revenues/(expenses) 193.4 (2.7) (190.7) -
Capital expenditures 100.4 30.5 53.6 184.5
As at December 31, 2005
Total assets 3,063.9 582.6 352.1 3,998.6
Investments subject to
significant influence - 3.9 92.8 96.7
Goodwill - 97.1 - 97.1
Goodwill included in loss on
disposition - - 7.4 7.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x)Other consists of corporate activities and adjustments to reconcile to
consolidated balances.
4. EMPLOYEE FUTURE BENEFITS
NOVA SCOTIA POWER
NSPI maintains contributory defined-benefit and defined-contribution
pension plans, which cover substantially all of its employees, and plans
providing non-pension benefits for its retirees.
Defined benefit pension plans are based on the years of service and
average salary at the time the employee terminates employment and provide
annual post-retirement indexing equal to the change in the Consumer Price
Index up to a maximum increase of 6% per year.
Other retirement benefit plans include: unfunded pension arrangements
(with the same indexing formula as the funded pension arrangements), unfunded
long service award (which is impacted by expected future salary levels) and
contributory health care plan.
The measurement date for the assets and obligations of each benefit plan
is December 31, 2006.
Valuation date for defined-benefit plans
NSPI has a December 31 valuation date for accounting purposes. The most
recent and the next required actuarial valuation dates for funding purposes
are as follows:
Most recent Next required
actuarial valuation actuarial valuation
------------------------------------------------------------------------
Employee pension plan December 31, 2006 December 31, 2007
Acquired companies pension plan December 31, 2006 December 31, 2007
------------------------------------------------------------------------
------------------------------------------------------------------------
Total cash amount
Total cash amount for 2006, made up of NSPI contributions to its funded
defined-benefit pension plans, contributions to its defined-contribution
pension plan, employer paid premiums for its post-retirement health care plan,
and amounts paid directly to retirees and beneficiaries in other plans, was
$22.8 million (2005 - $29.9 million).
Accrued pension and non-pension benefit asset (liability)
2006 2005
-----------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefit pension benefit
millions of dollars plans plans plans plans
-------------------------------------------------------------------------
Assumptions (weighted average)
Accrued benefit obligation -
December 31:
Discount rate 5.25% 5.25% 5.25% 5.25%
Rate of compensation increase 3.0 to 3.0 to 3.0 to 3.0 to
5.5% 5.5% 5.5% 5.5%
Health care trend - initial
(next year) - 8.0% - 9.0%
- ultimate - 4.0% - 4.0%
- year ultimate
reached - 2011 - 2011
Benefit cost for year ending
December 31:
Discount rate 5.25% 5.25% 6.0% 6.0%
Expected long-term return on plan
assets 7.5% - 7.5% -
Rate of compensation increase 3.0 to 3.0 to 3.0 to 3.0 to
5.5% 5.5% 5.5% 5.5%
Health care trend - initial
(current year) - 9.0% - 10.0%
- ultimate - 4.0% - 4.0%
- year ultimate
reached - 2011 - 2011
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accrued benefit obligations
Balance, January 1 $ 777.5 $ 34.8 $ 640.3 $ 31.1
Employer current service cost 12.6 1.3 9.6 1.2
Employee contributions 4.7 - 4.7 -
Interest cost 40.4 1.8 38.1 1.8
Past service amendments - 2.4 - -
Actuarial (gains) losses (1.5) 1.9 114.3 3.2
Benefits paid (31.0) (2.6) (30.2) (2.5)
Other - - 0.7 -
-------------------------------------------------------------------------
Balance, December 31 802.7 39.6 777.5 34.8
-------------------------------------------------------------------------
Fair value of plan assets
Balance, January 1 581.2 - 516.0 -
Employer contributions 19.6 2.6 26.7 2.5
Employee contributions 4.7 - 4.7 -
Actual investment income 82.0 - 64.0 -
Benefits paid (31.0) (2.6) (30.2) (2.5)
-------------------------------------------------------------------------
Balance, December 31 656.5 - 581.2 -
-------------------------------------------------------------------------
Reconciliation of financial status
to accrued benefit asset,
December 31
Fair value of plan assets 656.5 - 581.2 -
Accrued benefit obligations 802.7 39.6 777.5 34.8
-------------------------------------------------------------------------
Plan deficit (146.2) (39.6) (196.3) (34.8)
Unamortized past service (gains)
costs (0.5) 2.3 (0.6) -
Unamortized actuarial losses (gains) 213.2 0.6 273.5 (1.6)
Unamortized transitional obligation 0.1 13.4 0.1 15.7
-------------------------------------------------------------------------
Accrued benefit asset (liability) $ 66.6 $ (23.3) $ 76.7 $ (20.7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The expected return on plan assets is determined based on the
market-related value of plan assets of $578.1 million at January 1, 2006 (2005
- $550.9 million), adjusted for interest on certain cash flows during the
year.
Defined benefit plans asset allocation
(% of plan assets) 2006 2005
-----------------------------------------
Employee Acquired Employee Acquired
pension companies pension companies
plan pension plan pension
plan plan
-----------------------------------------
Equity securities 69% 62% 66% 60%
Debt securities 29% 37% 33% 37%
Cash 2% 1% 1% 3%
-------------------------------------------------------------------------
Total 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2006, the pension funds do not hold any material
investments in Emera Inc. or Nova Scotia Power Inc. securities. Any such
investment would primarily be held indirectly through pooled investment funds.
Plans with accrued benefit obligations in excess of assets
As at December 31, 2006, all post-retirement benefit plans have accrued
benefit obligations in excess of assets.
Benefits cost components
millions of dollars 2006 2005
-----------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefit pension benefit
plans plan plans plan
-----------------------------------------
Costs arising from events
during the year:
Current service costs $ 12.6 $ 1.3 $ 9.6 $ 1.2
Interest on accrued benefits 40.4 1.8 38.1 1.8
Less: actual return on plan assets (82.0) - (64.0) -
Actuarial (gains) losses on
accrued benefit obligation (1.5) 1.9 114.3 3.2
Past service costs - 2.3 - -
Other - - 0.7 -
-------------------------------------------------------------------------
Future benefit costs before
adjustments (30.5) 7.3 98.7 6.2
Adjustments to recognize long-term
nature of costs:
Difference between expected return
on assets and actual return 38.9 - 23.0 -
Amortization of transitional
obligation - 2.3 - 2.2
Difference between amortization
of actuarial losses (gains) and
actual actuarial losses (gains)
on accrued benefit obligations 21.4 (2.0) (105.1) (3.6)
Difference between amortization
of past service costs and past
service costs for the year - (2.4) - -
-------------------------------------------------------------------------
Total cost recognized $ 29.8 $ 5.2 $ 16.6 $ 4.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Defined contribution plan
Employer cost $ 0.7 - $ 0.7 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sensitivity analysis for non-pension benefits plans
The health care cost trend significantly influences the amounts presented
for health care plans. An increase or decrease of one percentage point of the
assumed health care cost trend would have had the following impact in 2006:
millions of dollars Increase Decrease
-------------------------------------------------------------------------
Current service cost and interest cost $ 0.2 $ (0.2)
Accrued benefit obligation, December 31 $ 2.1 $ (1.7)
-------------------------------------------------------------------------
BANGOR HYDRO
BHE maintains a non-contributory defined-benefit and a contributory
defined-contribution pension plan, which cover substantially all of its
employees, and a health care plan for its retirees. The defined benefit
pension is based on the years of service and average salary at the time the
employee terminates employment and provides no post-employment indexing. The
defined benefit pension plan was closed to new entrants effective February
2006.
Other retirement benefit plans include an unfunded pension arrangement and
a contributory health care plan.
The measurement date for the assets and obligations of each benefit plan
is December 31, 2006.
Valuation date for defined-benefit plans
BHE has a December 31 valuation date for accounting purposes. The most
recent and the next required actuarial valuation dates for funding purposes
are the following:
Most recent Next required
actuarial valuation actuarial valuation
-------------------------------------------------------------------------
Employee pension plan December 31, 2005 December 31, 2006
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total cash amount
Total cash amount for 2006, made up of BHE contributions to its funded
defined-benefit pension plan, contributions to its defined contribution
pension plan, employer paid premiums for its post-retirement health care plan,
and amounts paid directly to retirees and beneficiaries in other plans, was
$10.7 million (2005 - $5.3 million).
Accrued pension and non-pension benefit
liability
millions of dollars 2006 2005
-----------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefit pension benefit
plans plans plans plans
-----------------------------------------
Assumptions (weighted average)
Accrued benefit obligation -
December 31:
Discount rate 6.00% 6.00% 5.75% 5.75%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
Health care trend - initial
(next year) - 8.40% - 9.20%
- ultimate - 5.00% - 5.00%
- year ultimate
reached - 2011 - 2011
Benefit cost for year ending
December 31:
Discount rate 5.75% 5.75% 6.00% 6.00%
Expected long-term return on plan
assets 8.00% 5.00% 8.00% 5.00%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
Health care trend - initial
(current year) - 9.20% - 10.80%
- ultimate - 5.00% - 5.00%
- year ultimate
reached - 2011 - 2010
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accrued benefit obligations
Balance, January 1 $ 85.8 $ 35.6 $ 86.8 $ 33.9
Employer current service cost 1.5 0.7 1.6 0.8
Interest cost 4.7 1.8 5.0 2.2
Past service amendments (0.3) - - (5.0)
Actuarial (gains) losses (3.2) 1.9 0.1 7.3
Benefits paid (4.3) (2.3) (4.6) (2.5)
Foreign currency translation
adjustment (0.2) 0.1 (3.1) (1.1)
-------------------------------------------------------------------------
Balance, December 31 84.0 37.8 85.8 35.6
-------------------------------------------------------------------------
Fair value of plan assets
Balance, January 1 50.6 1.0 51.0 1.1
Employer contributions 8.2 2.3 2.7 2.4
Actual investment income 5.2 - 3.1 -
Benefits paid (4.3) (2.3) (4.6) (2.4)
Foreign currency translation
adjustment 0.2 0.2 (1.6) (0.1)
-------------------------------------------------------------------------
Balance, December 31 59.9 1.2 50.6 1.0
-------------------------------------------------------------------------
Reconciliation of financial
status to accrued benefit
asset, December 31
Fair value of plan assets 59.9 1.2 50.6 1.0
Accrued benefit obligations 84.0 37.8 85.8 35.6
-------------------------------------------------------------------------
Plan deficit (24.1) (36.6) (35.2) (34.6)
Unamortized past service costs
(gains) 1.5 (4.4) 2.1 (4.8)
Unamortized actuarial losses 18.4 10.8 24.0 9.7
Unamortized transitional
obligation - 3.5 - 4.1
-------------------------------------------------------------------------
Accrued benefit liability $ (4.2) $ (26.7) $ (9.1) $ (25.6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the defined benefit pension plan, the expected return on plan assets
is determined based on the market-related value of plan assets of
$51.9 million at January 1, 2006 (January 1, 2005 - $52.8 million), adjusted
for interest on certain cash flows during the year.
Defined benefit plans asset allocation
(% of plan assets) 2006 2005
-----------------------------------------
Employee pension Employee pension
plan plan
-------------------------------------------------------------------------
Equity securities 59% 62%
Debt securities 40% 37%
Other 1% 1%
-------------------------------------------------------------------------
Total 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2006, the pension fund does not directly hold any
investments in Emera or Bangor Hydro securities. However, as a significant
portion of assets for the benefit plans are held in mutual funds, there may be
indirect investments in these securities.
Plans with accrued benefit obligation in excess of assets
As at December 31, 2006, all post-retirement benefit plans have accrued
pension obligations in excess of assets.
Benefits cost components
millions of dollars 2006 2005
-----------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefit pension benefit
Defined benefit plan plans plan plans plan
-----------------------------------------
Costs arising from events during
the year:
Current service costs $ 1.5 $ 0.7 $ 1.6 $ 0.8
Interest on accrued benefits 4.7 1.8 5.0 2.2
Less: actual return on plan assets (5.2) - (3.1) -
Actuarial (gains) losses on
accrued benefit obligation (3.2) 1.9 0.1 7.3
Past service gains (0.3) - - (5.0)
-------------------------------------------------------------------------
Future benefit costs before
adjustments (2.5) 4.4 3.6 5.3
Adjustments to recognize long-term
nature of costs:
Difference between expected return
on assets and actual return 1.0 - (1.2) -
Amortization of transitional
obligation - 0.6 - 0.6
Difference between amortization
of actuarial losses (gains) and
actual actuarial losses (gains)
on accrued benefit obligations 4.5 (1.1) 0.9 (6.6)
Difference between amortization
of past service costs and past
service costs for the year 0.6 (0.5) 0.4 5.0
-------------------------------------------------------------------------
Total cost recognized $ 3.6 $ 3.4 $ 3.7 $ 4.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Defined contribution plan
Employer cost $ 0.2 - $ 0.2 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sensitivity analysis for non-pension plans
The health care cost trend significantly influences the amounts presented
for health care plans. An increase or decrease of one percentage point of the
assumed health care cost trend would have had the following impact in 2006:
Increase Decrease
-------------------------------------------------------------------------
Current service cost and interest cost $ 0.6 $ (0.3)
Accrued benefit obligation, December 31 $ 6.5 $ (5.1)
-------------------------------------------------------------------------
Accounting for the impact of rate regulation:
When Bangor Hydro was purchased by Emera, BHE received regulatory approval
to continue amortizing certain existing schedules over a period of 10 years.
Under GAAP, as a result of the purchase, these unamortized balances would have
been recognized immediately in the year BHE was purchased. In the absence of
the regulatory policy, BHE's total accrued benefit liability would be $47.1
million (2005 - $53.0 million) and the total defined benefits expense for 2006
would be $4.8 million (2005 - $5.8 million).
5. OPERATING LEASES
The Company has entered into operating lease agreements for office space,
telecommunication services, and certain other equipment, which expire in 2007
to 2020. Future minimum annual lease payments under the leases are as follows:
millions of dollars
-------------------------------------------------------------------------
2007 $ 7.4
2008 6.7
2009 6.2
2010 4.9
2011 1.5
Thereafter 2.9
-------------------------------------------------------------------------
$ 29.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the year ended December 31, 2006 the Company recognized $7.1 million
(2005 - $6.2 million) in operating, maintenance and general expense.
6. INVESTMENTS AND EQUITY EARNINGS
Investments are comprised of the following:
2006 2005
-----------------------------------------
millions of dollars Carrying Equity Carrying Equity
value earnings value earnings
-------------------------------------------------------------------------
Equity accounted investments
Maritimes & Northeast Pipeline $ 95.8 $ 4.9 $ 92.8 $ 6.5
Maine Yankee Atomic Power Company 1.4 - 2.4 -
Maine Electric Power Company Inc. 1.3 - 1.5 -
-------------------------------------------------------------------------
Total equity investments 98.5 4.9 96.7 6.5
Long-term portfolio investments 2.8 - 2.4 -
-------------------------------------------------------------------------
$ 101.3 $ 4.9 $ 99.1 $ 6.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. INTEREST
Interest expense consists of the following:
millions of dollars 2006 2005
-------------------------------------------------------------------------
Interest on long-term debt $ 104.4 $ 104.8
Interest on short-term debt 16.5 14.6
Amortization of debt financing 1.8 1.9
Foreign exchange gains (losses) 4.4 (3.9)
-------------------------------------------------------------------------
$ 127.1 $ 117.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
8. OTHER INCOME
During 2006, Nova Scotia Power received an $8.9 million insurance
settlement on a petcoke supply interruption claim related to 2005.
During 2005, Nova Scotia Power received a payment of $10.5 million, less
$2.5 million of associated costs, from a gas supplier as part of
renegotiations and resolution of certain contractual matters.
9. INCOME TAXES
The income tax provision differs from that computed using the statutory
rates for the following reasons:
millions of dollars 2006 2005
-------------------------------------------------------------------------
Earnings before income taxes $ 226.5 $ 176.7
-------------------------------------------------------------------------
Income taxes, at statutory rates 86.3 38.1% 67.4 38.1%
Unrecorded future income taxes on
regulated earnings 4.2 1.9 (10.8) (6.1)
Equity earnings not subject to tax (1.9) (0.8) (2.7) (1.5)
Large corporations tax - - 4.2 2.4
Other (1.2) (0.6) (4.6) (2.6)
-------------------------------------------------------------------------
87.4 38.6% 53.5 30.3%
------- -------
Income taxes - current 82.3 50.2
-------------------------------------------------------------------------
Income taxes - future $ 5.1 $ 3.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The future income tax assets and liabilities comprise the following:
Current portion Long-term portion
-----------------------------------------
millions of dollars 2006 2005 2006 2005
-------------------------------------------------------------------------
Future income tax assets:
Tax loss carry forwards $ 15.1 $ 7.8 $ 6.5 $ 14.6
Property, plant and equipment - - 1.6 3.2
Other 3.8 1.5 1.9 1.2
-------------------------------------------------------------------------
$ 18.9 $ 9.3 $ 10.0 $ 19.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax liabilities:
Property, plant and equipment $ 85.9 $ 80.0
Deferred charges 12.1 16.6
Deferred credits (7.9) (10.8)
Tax loss carry forwards (4.1) (2.6)
Financing - (4.2)
Other 0.2 (0.1)
-------------------------------------------------------------------------
$ 86.2 $ 78.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2006, the Company has tax losses of $67.9 million,
which are reflected in future income tax assets or netted against future
income liabilities as appropriate, and expire as follows:
millions of dollars
-------------------------------------------------------------------------
2008 $ 0.9
2009 3.6
2010 10.8
Thereafter 52.6
-------------------------------------------------------------------------
$ 67.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accounting for the impact of rate regulation:
At December 31, 2006, the unrecorded future income tax assets of NSPI are
approximately $34.0 million (2005 - $21.2 million), consisting of deductible
temporary differences of $97.1 million (2005 - $55.7 million). In the absence
of the UARB's approval of NSPI's taxes payable accounting policy, NSPI would
have had a future income tax recovery of $12.8 million in 2006 (2005 -
$18.0 million income tax expense).
10. NON-CONTROLLING INTEREST
The non-controlling interest consists of the preferred shares of Nova
Scotia Power Inc. and Bangor Hydro-Electric Company. Dividends on the
preferred shares and related taxes are reflected in non-controlling interest
expense.
Non-controlling interest expense consists of preferred share dividends
less a net recovery of income tax expense of $0.8 million (2005 -
$0.8 million). The income tax recovery of $6.4 million in 2006 (2005 -
$6.4 million) is reflected as a reduction of preferred share dividends with an
offsetting increase in income tax expense.
millions of dollars 2006 2005
-------------------------------------------------------------------------
Preferred share dividend $ 14.1 $ 14.1
Part VI.1 tax on preferred share dividends 5.6 5.6
Part I tax recovery related to the Part VI.1
tax deduction (6.4) (6.4)
-------------------------------------------------------------------------
$ 13.3 $ 13.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
11. EARNINGS PER SHARE
Earnings per share for 2006 are as follows:
2006
-----------------------------------------
Weighted
average
Net common
earnings shares EPS
($ millions)(millions) ($)
-------------------------------------------------------------------------
Basic EPS $ 125.8 110.5 $ 1.14
Series C preferred shares of NSPI 5.8 6.2 (0.01)
Series D preferred shares of NSPI 7.5 6.7 -
Restricted share units and deferred
share units - 0.5 (0.01)
-------------------------------------------------------------------------
Diluted EPS $ 139.1 123.9 $ 1.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Senior management share options, whose exercise price exceeded the average
market price for the period, were excluded from the above calculation because
they did not dilute earnings per share.
Earnings per share for 2005 are as follows:
2005
-----------------------------------------
Weighted
average
Net common
earnings shares EPS
($ millions)(millions) ($)
-------------------------------------------------------------------------
Basic EPS $ 121.2 109.5 $ 1.11
Series C preferred shares of NSPI 5.8 6.6 (0.01)
Series D preferred shares of NSPI 7.5 7.1 (0.01)
-------------------------------------------------------------------------
Diluted EPS $ 134.5 123.2 $ 1.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Restricted share units and deferred share units, and senior management
share options, whose exercise price exceeded the average market price for the
period, were excluded from the above calculation because they did not dilute
earnings per share.
12. ACCOUNTS RECEIVABLE
In May 2004 NSPI renewed a revolving non-recourse securitization agreement
with an independent trust administered by a major Canadian bank. Under the
securitization agreement NSPI sells an undivided co-ownership interest in
certain current and future accounts receivable generated in the normal course
of business. The amount of the accounts receivables sold is removed from the
balance sheet with each revolving securitization. NSPI also retains an
undivided co-ownership of approximately 10% in the receivables sold to the
trust. The retained interest is accounted for at carrying value in deferred
charges. Fees related to securitization are expensed as incurred.
At December 31, 2006 net accounts receivables sold amounted to $80 million
(2005 - $80 million). This agreement is in place until 2009 with the intention
that it will be renewed at that time.
At December 31, 2006, the Company had unbilled revenue included in
accounts receivable in the amount of $82.3 million (2005 - $71.8 million). The
unbilled revenue is an estimate of the amount of revenue related to energy
delivered to customers since the date their meter was last read. Actual
results may differ from this estimate.
NSPI's existing long-term natural gas purchase agreement includes a price
adjustment clause covering three years of natural gas purchases. The clause
states that NSPI will pay for all gas purchases at the agreed contract price,
but will be entitled to a price rebate on a portion of the volumes, to be
settled in November 2007. Management's best estimate of the price rebate,
based on the contract specifications using actual and forward market pricing,
of $68.9 million (2005 - $48.4 million) is reflected in accounts receivables.
In 2005, this receivable was classified in long-term receivables.
13. DEFERRED CHARGES AND CREDITS
Deferred charges and credits, including the impact of rate-regulated
accounting policies, include the following:
millions of dollars 2006 2005
-------------------------------------------------------------------------
Deferred charges:
Regulatory assets:
Pre-2003 income tax liability and related interest $ 147.1 $ 146.7
Unamortized defeasance costs 143.8 156.5
Costs to terminate/restructure purchased power
contracts 23.2 28.0
Seabrook nuclear project 17.6 19.6
Deferral of income and capital taxes not included
in Q1 2005 rates 16.7 16.7
Maine Yankee decommissioning costs 14.0 19.7
Stranded cost revenue requirement levelizers 10.1 13.3
Deferred restructuring costs 7.4 8.7
Hydro-Quebec obligation 4.5 5.2
Other 8.0 6.9
-------------------------------------------------------------------------
392.4 421.3
-------------------------------------------------------------------------
Non-regulatory assets:
Accrued pension and non-pension benefit asset (note 4) 43.3 56.0
Unamortized debt financing costs 13.0 14.7
Retained interest in accounts receivable securitized
(note 12) 8.1 7.6
Other 8.6 10.6
-------------------------------------------------------------------------
73.0 88.9
-------------------------------------------------------------------------
$ 465.4 $ 510.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deferred credits:
Regulatory liabilities:
Other $ 2.2 $ 3.4
-------------------------------------------------------------------------
2.2 3.4
-------------------------------------------------------------------------
Non-regulatory liabilities:
Accrued pension and non-pension benefit liability
(note 4) 30.9 34.7
Maine Yankee decommissioning liability 14.0 19.7
Hydro-Quebec obligation 4.5 5.2
Unearned revenue 3.1 5.0
Other 11.4 9.5
-------------------------------------------------------------------------
63.9 74.1
-------------------------------------------------------------------------
$ 66.1 $ 77.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory assets consist of:
Pre-2003 Income Tax Liability and Related Interest
NSPI has a regulatory asset related to pre-2003 income taxes that have
been paid, but not yet recovered from customers. This circumstance arose when
NSPI claimed capital cost allowance ("CCA") deductions in its income tax
returns that were ultimately disallowed by a decision of the Supreme Court of
Canada. NSPI applied to the regulator to include recovery of these costs in
customer rates. In its February 5, 2007 decision, the UARB approved recovery
of this regulatory asset over eight years, commencing April 1, 2007. In the
absence of UARB approved recovery, the liability would have been expensed when
incurred.
Unamortized Defeasance Costs
Upon privatization in 1992, NSPI became responsible for managing a
portfolio of approximately $1.05 billion of defeasance securities held in
trust. The excess of the cost of defeasance investments over the face value of
the related debt is deferred on the balance sheet and amortized over the life
of the defeased debt as permitted by the UARB. In the absence of UARB
approval, the losses would have been expensed as incurred and net earnings
would be $12.7 million higher in 2006 (2005 - $13.2 million).
Costs to Terminate/Restructure Purchased Power Contracts
Bangor Hydro has power purchase contracts, which it was required to
negotiate when oil prices were high, with several independent power producers
known as small power production facilities. The cost of power from these
facilities is more than Bangor Hydro would incur from other sources if it were
not obligated under these contracts. Bangor Hydro has been attempting to
alleviate the adverse impact of these high-cost contracts and in doing so has
incurred costs to terminate or restructure certain of the contracts. The MPUC
has allowed Bangor Hydro to defer these costs and recover them in stranded
cost rates. The contract termination was recovered over an 11-year period,
which ended in February 2006, while the contract restructuring is being
recovered over a 20-year period ending in June 2018. The annual amortization
is approximately $4.6 million, beginning in 2006. In the absence of the MPUC's
approval, these costs would have been expensed as incurred and earnings would
have been $4.6 million ($2.7 million after-tax) higher in 2006 (2005 -
$19.4 million or $11.7 million after-tax).
Seabrook Nuclear Project
Bangor Hydro was a participant in the Seabrook nuclear project in
Seabrook, New Hampshire. On December 31, 1984, Bangor Hydro had almost
$87 million invested in Seabrook, but because the uncertainties arising out of
the Seabrook Project were having an adverse impact on Bangor Hydro's financial
condition, an agreement for the sale of Seabrook was reached in mid-1985 and
was consummated in November 1986. In 1985, the MPUC issued an order
disallowing recovery of certain Seabrook costs, but provided for the recovery
through customer rates of 70% of Bangor Hydro's year-end 1984 investment in
Seabrook Unit 1 over 30 years ending in October, 2015. In the absence of MPUC
approval, the loss on sale would have been recognized when incurred and
earnings for 2006 would be $1.9 million ($1.1 million after-tax) higher (2005
- $2.1 million or $1.2 million after-tax).
Deferral of Income and Capital Taxes Not Included in Q1 2005 Rates
The UARB agreed to allow NSPI to defer taxes not reflected in rates for
the period January 1, 2005 until April 1, 2005, the date when new rates became
effective. In 2005, NSPI deferred $16.7 million consisting of $4.5 million of
provincial and federal grants and $12.2 million in income taxes reflecting
increases in these taxes since rates were last set in 2002. In its February 5,
2007 decision, the UARB approved recovery of this regulatory asset over eight
years, commencing April 1, 2007. In the absence of the UARB's approval, these
taxes would not have been deferred and net earnings would have been
$16.7 million lower in 2005.
Maine Yankee Decommissioning Costs
Bangor Hydro owns 7% of the common stock of Maine Yankee, which in 1997
permanently shutdown its nuclear generating plant. Pursuant to a contract with
Maine Yankee, BHE is required to pay its pro-rata share of Maine Yankee's
operating expenses including decommissioning costs. BHE's share of the
estimated decommissioning costs were approximately $4.7 million in 2006 (2005
- $5.0 million). Maine Yankee expense recovery is included in BHE's stranded
cost revenues, and along with all stranded cost revenues, purchased power, and
Hydro-Quebec costs, are fully recoverable starting March 1, 2005. For any
variance between the actual amount of these items and the amounts used in
setting rates, a regulatory deferral is recorded with a credit or charge to
regulatory amortizations. Any over or under-recovery will be reviewed at
future rate proceedings with the MPUC. In the absence of regulator approval,
the Maine Yankee decommissioning costs would have been expensed when incurred
and earnings would have been $4.7 million ($2.8 million after-tax) higher in
2006 (2005 - $5.0 million or $3.0 million after-tax).
Stranded Cost Revenue Requirement Levelizer
Bangor Hydro's current stranded cost rates are designed to recover their
cumulative stranded cost revenue requirements over a three-year period from
March 2005 to February 2008. While the stranded cost revenue requirements
differ throughout the period due to changes in purchased power expenses and
varying amortization periods for regulatory assets and liabilities, the annual
stranded cost revenues are the same during the period. To levelize the impact
of the varying revenue requirements, cost or revenue deferrals are recognized.
For the period March 2005 to February 2006 BHE deferred $15.0 million of costs
and will amortize the deferral almost evenly over the periods March 2006 to
February 2007, and March 2007 to February 2008. This levelizer is recognized
only as result of regulatory accounting and the stranded cost ratemaking
process. Absent regulatory accounting, the levelizer mechanism would not
exist, and the methodology for determining BHE's rates associated with
stranded costs is not known. In the absence of regulatory approval, earnings
for 2006 would be $3.9 million ($2.3 million after-tax) higher (2005 -
$13.9 million lower or $8.4 million after-tax).
Deferred Restructuring Costs
In order to provide rate stability, the UARB allows NSPI to defer the cost
of large early retirement and severance programs, and amortize the resulting
deferred charges on a straight-line basis over a three-year period, commencing
in the period in which the program is initiated.
In conjunction with Bangor Hydro's Alternative Rate Plan, BHE has been
provided with accounting orders from the MPUC to defer and amortize over ten
years certain employee transition costs. Eligible for deferral are the 2002
and 2003 employee transition costs related to reductions in the cost of
operations and employee transition costs associated with Bangor Hydro's
automated meter reading project and the outsourcing of information technology
support in 2004 and 2005.
In the absence of regulator approval, these costs would have been expensed
as incurred and 2006 earnings would be $1.3 million ($0.8 million after-tax)
higher (2005 - $2.1 million or $2.0 million after-tax).
Hydro-Quebec Obligation
The obligation associated with Hydro-Quebec represents the estimated
present value of Bangor Hydro's estimated future payments for net costs
associated with ownership and operation of the Hydro-Quebec intertie between
the New England utilities and Hydro-Quebec. The obligation has been recognized
as a long-term deferred credit, and the MPUC has permitted recovery of this
obligation. The regulatory asset and obligation are being reduced as expenses
are incurred with the reduction of the regulatory asset amortized to purchase
power expense. In the absence of regulator approval, 2006 earnings would be
$0.5 million ($0.3 million after-tax) higher (2005 - $0.5 million or
$0.3 million after-tax).
Other
Bangor Hydro has other regulatory assets, which are being amortized to net
earnings over varying lives. These deferred costs would have been expensed as
incurred in the absence of approval from one of its regulators, and earnings
would have been $2.7 million ($1.6 million after-tax) higher in 2006 (2005 -
$4.1 million or $2.4 million after-tax).
Regulatory liabilities include:
Other
Bangor Hydro has other regulatory liabilities, which are being amortized
to net earnings over varying lives. These deferred gains would have been
expensed as incurred in the absence of approval from one of its regulators,
and earnings would have been $1.2 million ($0.7 million after-tax) lower in
2006 (2005 - $0.9 million or $0.6 million after-tax).
14. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
2006
-----------------------------------------
Accumu-
lated Net
Depreci- Book
millions of dollars Cost ation Value
-------------------------------------------------------------------------
Generation
Thermal $1,744.0 $ 676.7 $1,067.3
Gas Turbines 32.1 21.8 10.3
Combustion Turbines 76.7 13.2 63.5
Hydroelectric 434.6 129.5 305.1
Wind Turbines 2.1 0.4 1.7
Transmission 683.5 315.6 367.9
Distribution 1,324.1 611.7 712.4
Other 382.0 157.1 224.9
Other, under capital lease 3.8 0.5 3.3
-------------------------------------------------------------------------
$4,682.9 $1,926.5 $2,756.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2005
Restated (note 2)
-----------------------------------------
Accumu-
lated Net
Depreci- Book
millions of dollars Cost ation Value
-------------------------------------------------------------------------
Generation
Thermal $1,719.1 $ 634.1 $1,085.0
Gas Turbines 31.1 21.5 9.6
Combustion Turbines 76.5 10.5 66.0
Hydroelectric 427.6 123.4 304.2
Wind Turbines 2.0 0.3 1.7
Transmission 673.4 300.1 373.3
Distribution 1,285.3 571.2 714.1
Other 371.6 137.2 234.4
Other, under capital lease 0.9 - 0.9
-------------------------------------------------------------------------
$4,587.5 $1,798.3 $2,789.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accounting for the impact of rate regulation:
At December 31, 2006, the Glace Bay generating station had a net book
value of $5.1 million (2005 - $12.9 million). During the year NSPI amortized
$8.6 million (2005 - $6.2 million) related to the plant, and capitalized
$0.8 million in AFUDC (2005 - $1.3 million) to the plant value. In the absence
of the UARB's approved accounting policies, the generation station would have
been written off in the year when NSPI determined that the unamortized cost of
the generating station would not be recoverable.
15. ACQUISITION
On May 24, 2005 Emera and Brookfield Power Corporation (formerly Brascan
Power Corporation), in a 50/50 joint venture, acquired Bear Swamp, a 600
megawatt ("MW") pumped storage hydro-electric facility in northern
Massachusetts. Emera's share of the purchase price was $61.2 million. The
facility sells energy, capacity and ancillary products to the New England
Power Pool. Also included in the acquisition is the nearby 10 MW Fife Brook
run-of-river hydro-electric facility.
The acquisition has been accounted for under the purchase method of
accounting using proportionate consolidation, and accordingly, Emera's pro-
rata share of the results of operations since the date of acquisition have
been included in the consolidated statement of earnings.
Emera's share of the transaction is summarized as follows:
Net assets acquired million of dollars
-------------------------------------------------------------------------
Inventory $ 0.2
Property, plant and equipment 61.8
Deferred charges 0.2
Accrued liabilities (0.1)
Deferred credits (0.9)
-------------------------------------------------------------------------
Total cash consideration $ 61.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
16. DISCONTINUED OPERATIONS AND DISPOSAL OF LONG-LIVED ASSETS
Effective September 30, 2005 Emera Fuels, a subsidiary of Emera, sold its
heating oil distribution business. Emera Fuels is included in the segment
"Other" in Note 3 Segment Information.
Emera Fuels has been accounted for as discontinued operations.
Accordingly, prior periods have been reclassified to reflect this change. The
following provides additional information with respect to amounts included in
loss from discontinued operations on the consolidated statements of earnings:
millions of dollars 2005
-------------------------------------------------------------------------
Revenue $ 69.7
Earnings before income taxes $ 0.3
Loss on disposition, net of tax $ (1.6)
-------------------------------------------------------------------------
The following summarizes the transaction:
millions of dollars
-------------------------------------------------------------------------
Cash proceeds on disposition $ 18.6
Disposition costs 0.2
-------------------------------------------------------------------------
Net cash proceeds on disposition 18.4
Net assets included in disposition 19.3
-------------------------------------------------------------------------
Loss on disposition 0.9
Income taxes 0.7
-------------------------------------------------------------------------
Loss on disposition, net of tax $ 1.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
17. INTEREST IN JOINT VENTURES
The following amounts represent the Company's proportionate interest in
its joint ventures' financial position, operating results, and cash flows
included in the consolidated financial statements:
millions of dollars 2006 2005
-------------------------------------------------------------------------
Current assets $ 8.1 $ 3.3
Non-current assets 58.7 59.3
-------------------------------------------------------------------------
$ 66.8 $ 62.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities $ 4.9 $ 3.4
Non-current liabilities 0.1 -
-------------------------------------------------------------------------
$ 5.0 $ 3.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenues $ 30.5 $ 26.6
Expenses (28.0) (24.1)
-------------------------------------------------------------------------
Net earnings $ 2.5 $ 2.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash (used in) provided by operations $ (1.2) $ 7.0
Cash used in investing activities (0.7) (62.6)
Cash provided by financing activities 0.1 57.5
-------------------------------------------------------------------------
(Decrease) increase in cash $ (1.8) $ 1.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
18. GOODWILL
The change in goodwill is due to the following:
millions of dollars 2006 2005
-------------------------------------------------------------------------
Balance, beginning of year $ 97.1 $ 107.7
Disposition of Emera Fuels - (7.4)
Change in foreign exchange rate - (3.2)
-------------------------------------------------------------------------
Balance, end of year $ 97.1 $ 97.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
19. ASSET RETIREMENT OBLIGATIONS
Asset retirement obligations are recognized when incurred and represent
the fair value, using the Company's credit-adjusted risk-free rate, of the
Company's estimated future cash flows necessary to discharge legal obligations
related to reclamation of land at the Company's thermal, hydro and combustion
turbine sites, and disposal of PCBs in its transmission and distribution
equipment. Estimated future cash flows are based on the Company's completed
depreciation studies, prior experience, estimated useful lives, and
governmental regulatory requirements. Actual results may differ from these
estimates.
The change in asset retirement obligations is due to the following:
2006 2005
Restated
millions of dollars (note 2)
-------------------------------------------------------------------------
Balance, beginning of year $ 74.1 $ 70.8
Accretion included in depreciation expense 2.0 0.9
Accretion deferred to regulatory asset 2.1 2.8
Liabilities settled (0.1) -
Disposition of Emera Fuels - (0.2)
Other - (0.2)
-------------------------------------------------------------------------
Balance, end of year $ 78.1 $ 74.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The key assumptions used to determine the asset retirement obligations are
as follows:
-------------------------------------------------------------------------
Estimated
undis-
counted
future
Credit- obliga-
adjusted tion
risk- (millions Expected
free of settlement
Asset rate dollars) date
-------------------------------------------------------------------------
Thermal 5.3% $ 242.3 14 - 33 years
Hydro 5.3% 60.8 25 - 55 years
Combustion Turbines 5.3% 5.1 1 - 17 years
Transmission & Distribution 5.3% 7.2 1 - 19 years
Other 7.4% - 8.6% 0.5 4 - 9 years
-------------------------------------------------------------------------
$ 315.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Some of the Company's hydro, transmission and distribution assets may have
additional asset retirement obligations. As the Company expects to use the
majority of its installed assets for an indefinite period, no removal date can
be determined and consequently a reasonable estimate of the fair value of any
related asset retirement obligation cannot be made at this time.
Accounting for the impact of rate regulation:
Any difference between the amount approved by the regulator of Nova Scotia
Power as depreciation expense and the amount that would have been calculated
under the accounting standard for asset retirement obligations is recognized
as a regulatory asset in property, plant and equipment. In the absence of this
deferral, net earnings for 2006 would be $2.1 million lower (2005 - $2.8
million).
20. SHORT-TERM DEBT
For the year ended December 31, 2006, short-term debt consists of:
- LIBOR loans of $122.1 million issued against lines of credit. LIBOR
loans bear interest at prevailing market rates, which on December 31,
2006, averaged 5.94%.
- Advances of $11.1 million against the operating line of credit, which
when drawn upon, bears interest at the prime rate, which on
December 31, 2006, was 6.00%.
This short-term debt is unsecured.
For the year ended December 31, 2005, short-term debt consists of:
- LIBOR loans of $58.1 million issued against lines of credit. LIBOR
loans bear interest at prevailing market rates, which on December 31,
2005, averaged 4.93%.
- Advances of $5.4 million against the operating line of credit, which
when drawn upon, bears interest at the prime rate, which on
December 31, 2005, was 5.00%.
- Bangor Hydro borrowings under its revolving credit loan agreement of
$21.1 million that bears interest at 5.1%.
- Emera Energy Services' US base rate loan for $3.5 million that bears
interest at 7.25% (US prime).
This short-term debt is unsecured.
21. LONG-TERM DEBT
Long-term debt includes the issues detailed below. All long-term debt
instruments are issued under trust indentures at fixed interest rates, and are
unsecured unless noted below. Also included are certain bankers acceptances
and commercial paper where the Company has the intention and the unencumbered
ability to refinance the obligations for a period greater than one year.
Effective Average Amount
Interest Rate % Years of Outstanding
millions of dollars 2006 2005 Maturity 2006 2005
-------------------------------------------------------------------------
Emera
Bankers Acceptances and
Advances 5.23 - 1 year $ 111.0 -
renewal
Medium Term Notes - 6.000 - - $ 100.0
Private Placement - secured
by a letter of credit - 6.297 - - 10.0
NSPI
Medium Term Notes 6.64 6.61 2008-2097 1,250.0 1,250.0
Debentures 9.75 9.75 2019 95.0 95.0
Commercial paper 4.29 3.02 1 year 57.0 182.0
renewal
Capital lease obligations 4.44 4.41 2013 3.8 0.9
Bangor Hydro
(issued and payable in US$)
General & Refunding Mortgage
Bonds - secured by first
mortgage indentures 9.74 9.74 2020-2022 58.3 58.3
Municipal Review Committee 5.00 5.00 2007-2008 4.1 6.9
Senior unsecured note 6.09 6.09 2012 23.3 23.3
Senior unsecured notes 5.31 5.31 2008-2018 58.3 58.3
-------------------------------------------------------------------------
1,660.8 1,784.7
Less: Amount due within one year 3.4 152.9
-------------------------------------------------------------------------
$1,657.4 $1,631.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
An NSPI medium term note ("MTN") of $40.0 million bearing interest at
5.20%, maturing in 2029, was redeemable at the option of the holder in 2006.
None of this issue was redeemed and the interest rate on the MTN is 6.28%
until maturity. Another NSPI MTN of $40.0 million, maturing in 2026, is
extendable until 2056 at the option of the holder.
As at December 31, 2006 long-term debt and obligations under a capital
lease are due as follows:
millions of dollars
-------------------------------------------------------------------------
Year of Maturity
-------------------------------------------------------------------------
One year renewable $ 168.0
2007 3.4
2008 121.4
2009 130.3
2010 105.3
2011 5.3
Greater than 5 years 1,127.1
-------------------------------------------------------------------------
$1,660.8
-------------------------------------------------------------------------
22. COMMON SHARES
Authorized: Unlimited number of non-par value common shares.
Common
Share
Capital
Millions millions
of of
Issued and outstanding: Shares dollars
------------------------------------------------------------------------
January 1, 2005 108.87 $1,017.3
Issued for cash under purchase plans 0.43 7.9
Options exercised under senior management share option
plan 0.80 13.0
Share-based compensation - 1.0
------------------------------------------------------------------------
December 31, 2005 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
------------------------------------------------------------------------
------------------------------------------------------------------------
As at December 31, 2006, there were 4.9 million (2005 - 0.3 million)
common shares reserved for issuance under the senior management common share
option plan, and 1.2 million (2005 - 1.3 million) common shares reserved for
issuance under the employee common share purchase plan.
DIVIDEND REINVESTMENT AND EMPLOYEE COMMON SHARE PURCHASE PLANS
The Company has a Common Shareholder Dividend Reinvestment Plan, which
provides an opportunity for shareholders to reinvest dividends and to make
cash contributions for the purpose of purchasing common shares. The Company
also has an Employee Common Share Purchase Plan to which the Company and
employees make cash contributions for the purpose of purchasing common shares
and which allows reinvestment of dividends.
SHARE-BASED COMPENSATION PLAN
Common Share Option Plan
The Company has a common share option plan that grants options to senior
management of the Company for a maximum term of ten years. The option price
for these shares is the closing market price of the shares on the day before
the option is granted.
All options granted to date are exercisable on a graduated basis with up
to 25 percent of options exercisable on the first anniversary date and in
further 25 percent increments on each of the second, third and fourth
anniversaries of the grant. If an option is not exercised within ten years, it
expires and the optionee loses all rights thereunder. The holder of the option
has no rights as a shareholder until the option is exercised and shares have
been issued. The maximum number of such shares optioned to anyone cannot
exceed one percent of the issued and outstanding common shares on the date the
option is granted.
If, before the expiry of an option in accordance with its terms, the
optionee ceases to be an eligible person due to retirement or a change of
responsibility at the Company's request, such option may, subject to the terms
thereof and any other terms of the plan, be exercised at anytime within the 24
months following the date the optionee retires, but in any case prior to the
expiry of the option in accordance with its terms.
If, before the expiry of an option in accordance with its terms, the
optionee ceases to be an eligible person due to employment termination for
just cause, resignation or death, such option may, subject to the terms
thereof and any other terms of the plan, be exercised at anytime within the
six months following the date the optionee is terminated, resigns, or dies, as
applicable, but in any case prior to the expiry of the option in accordance
with its terms.
2006 2005
-----------------------------------------
Weighted Weighted
Shares average Shares average
under exercise under exercise
option price option price
-------------------------------------------------------------------------
Outstanding, beginning
of year 1,696,475 $ 17.81 1,939,750 $ 16.76
Granted 578,700 $ 19.88 569,500 $ 19.46
Exercised (382,750) $ 19.20 (797,775) $ 16.43
Expired - - (15,000) $ 17.55
-------------------------------------------------------------------------
Outstanding, end of year 1,892,425 $ 18.54 1,696,475 $ 17.81
Exercisable, end of year 743,225 $ 17.45 702,750 $ 17.13
-------------------------------------------------------------------------
The weighted average contractual life of options outstanding at December
31, 2006 is 7.4 years (2005 - 7.6 years). The range of exercise prices for the
options outstanding at December 31, 2006 is $13.70 to $19.88 (2005 - $13.70 to
$19.50).
Deferred Share Unit Plan and Restricted Share Unit Plan
The Company has deferred share unit ("DSU") and restricted share unit
("RSU") plans.
Under the DSU plan Directors of the Company who are resident in Canada may
elect to receive all or any portion of their compensation in DSUs in lieu of
cash compensation. Directors' fees are paid on a quarterly basis and at the
time of each payment of fees, the applicable amount is converted to DSUs. A
DSU has a value equal to one Emera common share. When a dividend is paid on
Emera's common shares, the Director's DSU account is credited with additional
DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns, or
otherwise leaves the Board. The cash redemption value of a DSU equals the
market value of a common share at the time of redemption, pursuant to the
plan.
Under the DSU plan for executive and senior management, each participant
may elect to defer all or a percentage of their annual incentive award in the
form of DSUs with the proviso that for participants who are subject to
executive share ownership guidelines, a minimum of 50% of the value of their
actual annual incentive award (25% in the first year of the program) will be
payable in DSUs until the applicable guidelines are met.
When incentive awards are determined, the amount elected is converted to
DSUs, which have a value equal to the market price of a Company common share.
When a dividend is paid on Emera's common shares, each participant's DSU
account is allocated additional DSUs equal in value to the dividends paid on
an equivalent number of Emera common shares. Following termination of
employment or retirement, and by December 15 of the calendar year after
termination or retirement, the value of the DSUs credited to the participant's
account is calculated by multiplying the number of DSUs in the participant's
account by the then market value of an Emera common share.
In addition, special DSU awards may be made from time to time by the
Management Resources and Compensation Committee ("MRCC") to selected
executives and senior management to recognize singular achievements or to
achieve certain corporate objectives.
RSUs are granted annually for three-year overlapping performance cycles.
The first cycle ran from January 1, 2003 through December 31, 2005. RSUs are
granted at fair value on the grant date and dividend equivalents are awarded
and are used to purchase additional RSUs. The RSU value varies according to
the Company's common share market price and corporate performance.
RSUs vest at the end of the three-year cycle and will be calculated and
approved by the MRCC early in the following year. The value of the payout
considers actual service over the performance cycle and will be pro-rated in
the case of retirement, involuntary termination, disability or death.
Employee Employee Director
DSUs RSUs DSUs
Out- Out- Out-
standing standing standing
-------------------------------------------------------------------------
Balance at January 1, 2005 140,130 305,250 32,022
Granted 33,463 132,280 14,381
Retirement, termination, disability & death (43,307) (76,281) (6,967)
-------------------------------------------------------------------------
December 31, 2005 130,286 361,249 39,436
Granted 22,511 95,268 23,347
Retirement, termination, disability & death (311) (21,739) -
Payout - (139,693) -
-------------------------------------------------------------------------
December 31, 2006 152,486 295,085 62,783
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Company is using the fair value based method to measure the
compensation expense related to its share-based compensation and employee
purchase plan and recognizes the expense over the vesting period on a
straight- line basis. The DSU and RSU liabilities are marked-to-market at the
end of each period based on the common share price at the end of the period.
For the year ended December 31, 2006, $7.1 million (2005 - $3.7 million) of
compensation expense related to options granted, units issued, and shares
purchased by employees was recognized in operating, maintenance and general
expense.
The fair value of each option is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for the grants:
2006 2005
Expected dividend yield 5.12% 5.20%
Expected volatility 14.04% 14.12%
Risk-free interest rate 4.27% 4.32%
Expected life 7 years 7 years
23. CONTRIBUTED SURPLUS
The change in contributed surplus is due to the following:
millions of dollars 2006 2005
-------------------------------------------------------------------------
Balance, beginning of year $ 1.8 $ 1.9
Stock option expense 0.9 0.7
Exercise of stock options (0.5) (0.8)
-------------------------------------------------------------------------
Balance, end of year $ 2.2 $ 1.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
24. FINANCIAL INSTRUMENTS
The Company manages its exposure to foreign exchange, interest rate, and
commodity risks in accordance with established risk management policies and
procedures using derivative instruments consisting mainly of foreign exchange
forward contracts, interest caps and collars, and oil and gas options and
swaps.
Derivative financial instruments involve credit and market risks. Credit
risks arise from the possibility that a counterparty will default on its
contractual obligations and is limited to those contracts where the Company
would incur a loss in replacing the instrument.
Financial instruments include the following:
2006 2005
-------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
Liability Liability Liability Liability
millions of dollars (Asset) (Asset) (Asset) (Asset)
-------------------------------------------------------------------------
Long-term debt $1,660.8 $1,925.5 $1,784.7 $2,076.0
Short-term debt 133.2 129.2 88.1 88.1
Derivative financial instruments
(hedges)
Interest rate swaps - - 0.1 0.2
Interest rate caps and collars (0.1) (0.1) (0.3) (0.3)
Natural gas swaps - (4.4) (4.0) (13.4)
Oil swaps 0.4 (11.0) (3.5) (16.1)
Foreign exchange contracts (0.1) (7.2) - 33.9
Derivative financial instruments
(non-hedges)
Energy marketing assets (39.3) (39.3) (20.1) (20.1)
Energy marketing liabilities 38.1 38.1 15.0 15.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LONG-TERM DEBT AND SHORT-TERM DEBT
The fair value of Emera's long-term and short-term debt is estimated based
on the quoted market prices for the same or similar issues, or on the current
rates offered to Emera, for debt of the same remaining maturities.
DERIVATIVE FINANCIAL INSTRUMENTS
The fair value of derivative financial instruments is estimated by
obtaining prevailing market rates from investment dealers.
Interest Rates
The Company enters into interest rate hedging contracts to limit exposure
to fluctuations in floating and fixed interest rates on its short-term and
long-term debt.
Interest rate cap contracts limiting floating rate interest on
$225.0 million short-term debt over 2007 to a fixed interest rate of 4.75%
were outstanding at December 31, 2006. In addition, interest rate caps, at an
average rate of 4.06%, on $239 million short-term debt over 2006 matured in
January 2007.
Commodity Prices
The Company purchased natural gas swap contracts in 2006 to limit exposure
to fluctuations in natural gas prices. As at December 31, 2006, the Company
had hedged approximately 95% of all natural gas purchases associated with its
forecasted natural gas burn for 2007, 35% for 2008, 30% for 2009, and 30% for
2010. In addition, the Company has hedged approximately 95% of natural gas
sales associated with the Company's resale program for 2007, 70% for 2008, 65%
for 2009, and 65% for 2010.
The Company enters into oil swap contracts to limit exposure to
fluctuations in world prices of heavy fuel oil. As at December 31, 2006, the
Company has hedged approximately 100% of 2007 requirements and 35% of 2008
requirements, and 5% of 2009 requirements.
On December 31, 2006 the Company held non-hedging natural gas, power and
oil financial instruments which were marked-to-market.
Foreign Exchange
Emera enters into foreign exchange forward, option, and swap contracts to
limit exposure to currency rate fluctuations. Currency forwards are used to
fix the Canadian dollar cost to acquire US dollars, reducing exposure to
currency rate fluctuations. Forward contracts to buy US $815.4 million over
2007 to 2010 at a weighted average rate of CAD $1.1374 were outstanding at
December 31, 2006. Forward contracts to sell US $66.2 million in 2007 at a
weighted average rate of CAD $1.1404 were outstanding at December 31, 2006.
On December 31, 2006, the Company held non-hedging foreign exchange
financial instruments which were marked-to-market.
RISK MANAGEMENT
Commodity price and foreign exchange risk
A substantial amount of NSPI's fuel supply comes from international
suppliers, and is subject to commodity price and foreign exchange risk. NSPI
manages exposure to commodity price risk utilizing a combination of physical
fixed-price fuel contracts and financial instruments providing fixed or
maximum prices. Foreign exchange risk is managed through forward and option
contracts. The risk inherent in the Canadian dollar cost of fuel is measured
and managed on a portfolio basis.
The ability to switch fuel provides a dynamic, operational and effective
option in managing commodity price and supply risk.
Interest rate risk
The Company makes use of various financial instruments to hedge against
interest rate risk, as discussed above. Additionally, the Company uses
diversification as a strategy. It maintains a portfolio of debt instruments
which includes short-term instruments and long-term instruments with staggered
maturities. The Company also deals with several counterparties so as to
mitigate interest rate concentration risk.
Credit risk
The Company is exposed to credit risk with respect to amounts receivable
from customers. Credit assessments are conducted on all new customers and
deposits are requested on any high risk accounts. The Company also maintains
provisions for potential credit losses, which are assessed on a regular basis.
With respect to customers other than electric customers, counterparty
creditworthiness is assessed through reports of credit rating agencies or
other available financial information.
25. FOREIGN EXCHANGE TRANSLATION ADJUSTMENT
The change in foreign exchange translation adjustment is due to the
following:
millions of dollars 2006 2005
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Balance, beginning of year $ (98.2) $ (82.0)
Effect of exchange rate changes (2.0) (16.2)
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Balance, end of year $ (100.2) $ (98.2)
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26. RELATED PARTY TRANSACTIONS
In the ordinary course of business, Emera purchased natural gas
transportation capacity totaling $29.3 million (2005 - $21.7 million) during
the year ended December 31, 2006, from the Maritimes & Northeast Pipeline, an
investment under significant influence of the Company. The amount is
recognized in fuel for generation and purchased power or netted against energy
marketing margin in other revenue, and is measured at the exchange amount. At
December 31, 2006 the amount payable to the related party is $3.4 million
(2005 - $4.5 million), is non-interest bearing and is under normal credit
terms.
27. CONTINGENCIES
The Company has commenced arbitration against Aliant Inc., Bell Aliant
Regional Communications LP and its related parties ("Aliant") claiming, that
in 2003, Aliant unlawfully purported to terminate a certain telecommunications
services agreement and related agreements pursuant to which Aliant, using
certain assets sold by the Company to Aliant in 2000, provides
telecommunications services to the Company at a certain price. Aliant has
counterclaimed, claiming service fees it alleges are due in excess of the
contract price provided in the telecommunications services agreement. The
Company claims various remedies in respect of the telecommunications services
agreement and related agreements. The outcome, and therefore an estimate of
any contingent loss, of this litigation are not determinable.
A number of individuals who live in proximity to the Company's Trenton
Generating Station have filed a statement of claim against Nova Scotia Power
in respect of emissions from the operation of the plant for the period 2001
forward. The plaintiffs claim unspecified damages as a result of interference
with enjoyment of, or damage to, their property and adverse health effects
they allege were caused by such emissions. The outcome, and therefore an
estimate of any contingent loss, of this litigation are not determinable.
Bangor Hydro Electric has a potential liability to Great Lake Hydro
America LLC for headwater benefits on the Penobscot River in connection with
hydro assets sold to PPL Generation, LLC in 1999. The matter is currently
before the Federal Energy Regulatory Commission for determination. The
outcome, and therefore an estimate of any contingent loss, of this litigation
are not determinable.
In addition, the Company may, from time to time, be involved in legal
proceedings, claims and litigations that arise in the ordinary course of
business which the Company believes would not reasonably be expected to have a
material adverse effect on the financial condition of the Company.
28. COMMITMENTS
In addition to commitments outlined in elsewhere in these notes, Emera had
the following significant commitments at December 31, 2006:
- The Company has an outsourcing commitment to a third party, beginning
in early 2004 for seven years, at an annual cost ranging from
$8.6 million to $10.4 million.
- NSPI has an annual requirement to purchase approximately 366 GWh of
electricity from independent power producers over varying contract
lengths ranging from seven to nineteen years.
- NSPI is required to purchase approximately 61,600 mmbtu of natural gas
per day for the next four years (subject to offshore gas production),
and an additional 4,000 mmbtu per day, at the option of the supplier,
for five years.
- NSPI has a commitment to purchase approximately 61,000 mmbtu per day of
transportation capacity on the Maritimes and Northeast Pipeline, a
related party, for the next four years, and an additional 4,000 mmbtu
per day, at the option of the supplier for five years. The commitment
includes renewal rights at NSPI's option for an indefinite period of
time, at an approximate cost of $16 million per year.
- NSPI is responsible for managing a portfolio of approximately
$1.05 billion of defeasance securities held in trust. The defeasance
securities must provide the principal and interest payment streams of
the related defeased debt. Approximately 71%, or $742 million, of the
defeasance portfolio consists of investments in the related debt,
eliminating all risk associated with this portion of the portfolio.
- NSPI has a commitment to a third party for the transportation of coal
for ten years beginning in late 2002 at an approximate cost of
$16 million per year.
- NSPI has a commitment to third parties for 2007 to 2010, to purchase
3.4 million cubic metric tons ("mts") of import coal, 936,000 mts of
petroleum coke, 960,000 mts of domestic coal and 5.1 million mts of
marine freight.
- NSPI has a commitment to a third party beginning in 2005 for 10 years
to operate a facility at an annual cost of $4 million per year.
- Bangor Hydro has various contracts committing it to purchase annually
approximately $12 million to $14 million of electricity for the period
from 2007 to 2017 from independent power producers.These commitments
are reduced to approximately $2 million from 2018 to 2023.
29. GUARANTEES
Emera had the following guarantees at December 31, 2006:
- The Company has letters of credit issued against its operating facility
totaling $20.6 million. Emera's outstanding letter of credit is to
secure payment to a vendor that expires in 2007 and is renewed
annually. Nova Scotia Power's letters of credit extend to 2007 and/or
are renewed annually and secure payments to various vendors and
obligations under an unfunded pension plan. Bangor Hydro's letters of
credit extend to 2007 and/or are renewed annually to secure payments to
a vendor and for obligations under an unfunded pension plan.
30. COMPARATIVE INFORMATION
Certain of the comparative figures have been reclassified to conform to
the financial statement presentation adopted for 2006.
OPERATING STATISTICS
FIVE-YEAR SUMMARY
Year Ended December 31 2006 2005 2004 2003 2002
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Electric energy
sales (GWh)
Residential 4,516.0 4,602.7 4,632.4 4,391.1 4,401.6
Commercial 3,621.1 3,614.1 3,567.4 3,586.1 3,401.8
Industrial 3,246.7 4,600.3 4,556.1 4,449.8 4,225.9
Other 1,550.8 902.7 819.1 1,375.4 1,641.8
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Total electric energy
sales 12,934.6 13,719.8 13,575.0 13,802.4 13,671.1
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Sources of energy (GWh)
Thermal - coal 9,128.1 9,116.3 9,490.2 9,218.7 8,861.6
- oil 431.9 1,581.3 1,699.3 1,537.2 289.2
- natural gas 390.3 194.3 97.0 119.5 1,578.7
Hydro 1,034.7 1,092.6 983.5 1,176.8 1,108.7
Wind 2.4 1.8 2.4 2.6 0.3
Purchases 3,144.7 2,961.6 2,339.9 2,724.5 2,765.9
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Total generation and
purchases 14,132.1 14,947.9 14,612.3 14,779.3 14,604.4
Losses and internal use 1,197.5 1,228.1 1,037.3 976.9 933.3
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Total electric energy
sold 12,934.6 13,719.8 13,575.0 13,802.4 13,671.1
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Electric customers
Residential 526,014 520,671 515,726 509,824 501,233
Commercial 50,780 50,321 49,353 48,846 47,914
Industrial 2,526 2,515 2,455 2,393 2,325
Other 9,378 9,094 8,684 8,341 11,663
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Total electric
customers 588,698 582,601 576,218 569,404 563,135
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Capacity
Generating nameplate
capacity (MW)
Coal fired 1,243 1,243 1,243 1,243 1,243
Dual fired 350 350 350 350 350
Gas turbines 323 323 319 274 225
Hydroelectric 1,005 1,005 395 395 395
Wind turbines 1 1 1 1 1
Independent power
producers 120 74 66 67 66
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3,042 2,996 2,374 2,330 2,280
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Total number of employees 2,149 2,075 2,249 2,359 2,476
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km of transmission lines 5,900 6,100 6,100 6,100 6,100
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km of distribution lines 33,000 32,000 32,000 32,000 32,000
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FIVE YEAR SUMMARY
Year Ended December 31
(millions of dollars) 2006 2005 2004 2003 2002
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Statements of Earnings
Information
Revenue $1,166.0 $1,168.0 $1,134.2 $1,146.8 $1,161.2
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Cost of operations
Fuel for generation and
power purchased 347.7 432.0 350.0 363.3 453.2
Operating, maintenance
and general 255.6 248.2 245.2 258.6 276.5
Provincial, state and
municipal taxes 48.0 48.4 46.3 40.9 30.1
Provincial tax deferral - (4.5) - - -
Depreciation 145.2 136.1 131.2 126.9 127.0
Regulatory amortization 22.8 19.4 26.1 18.2 23.9
Allowance for funds
used during
construction (5.8) (4.4) (4.0) (5.1) (4.9)
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813.5 875.2 794.8 802.8 905.8
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Earnings from operations 352.5 292.8 339.4 344.0 255.4
Equity earnings 4.9 6.5 6.2 8.6 7.0
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Earnings before interest
and income taxes 357.4 299.3 345.6 352.6 262.4
Interest 127.1 117.4 126.8 133.6 144.0
Amortization of defeasance
costs 12.7 13.2 15.1 16.7 19.4
Other income (8.9) (8.0) - - -
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Earnings before income
taxes 226.5 176.7 203.7 202.3 99.0
Income taxes 87.4 53.5 62.7 60.9 5.5
Income taxes deferral - (12.2) - - -
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Net earnings before non-
controlling interest 139.1 135.4 141.0 141.4 93.5
Non-controlling interest 13.3 13.3 13.4 13.2 10.6
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Net earnings from
continuing operations 125.8 122.1 127.6 128.2 82.9
(Loss) earnings from
discontinued operations - (0.9) 2.2 1.0 0.7
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Net earnings applicable
to common shares 125.8 121.2 129.8 129.2 83.6
Common dividends 98.3 97.4 95.5 92.8 84.4
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Earnings retained for
use in Company $ 27.5 $ 23.8 $ 34.3 $ 36.4 $ (0.8)
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Cost of fuel for
generation - coal $ 266.2 $ 260.9 $ 209.1 $ 211.9 $ 229.6
- oil 34.3 100.2 91.1 90.4 20.6
- natural
gas (41.6) (35.4) (30.6) (58.4) 62.5
Power purchased 88.8 106.3 80.4 119.4 140.5
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Total cost of fuel for
generation and power
purchased $ 347.7 $ 432.0 $ 350.0 $ 363.3 $ 453.2
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Balance Sheets
Information
Current assets $ 502.1 $ 391.5 $ 332.1 $ 305.5 $ 331.7
Other assets 574.5 678.8 742.0 705.6 600.3
Investments 101.3 99.1 96.8 102.8 112.2
Property, plant and
equipment 2,881.9 2,829.2 2,778.3 2,777.0 2,863.7
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Total assets $4,059.8 $3,998.6 $3,949.2 $3,890.9 $3,907.9
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Current liabilities $ 501.8 $ 506.4 $ 493.6 $ 520.2 $ 697.6
Other liabilities 231.8 233.4 231.5 207.8 193.0
Long-term debt 1,657.4 1,631.8 1,626.5 1,589.5 1,417.8
Non-controlling interest 260.7 260.8 260.8 260.8 267.5
Common shares 1,055.2 1,039.2 1,017.3 1,007.2 999.8
Contributed surplus 2.2 1.8 1.9 1.2 0.4
Foreign currency
translation adjustment (100.2) (98.2) (82.0) (61.1) 2.9
Retained earnings 450.9 423.4 399.6 365.3 328.9
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Total equity and
liabilities $4,059.8 $3,998.6 $3,949.2 $3,890.9 $3,907.9
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Statements of Cash flow
information
Cash provided by
operating activities $ 345.8 $ 164.3 $ 304.6 $ 251.9 $ 272.4
Cash used in investing
activities 203.0 $ 117.2 $ 214.5 $ 85.2 $ 109.6
Cash used in
(provided by)
financing activities $ 156.7 $ 68.3 $ 57.4 $ 184.4 $ 157.3
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Financial ratios
($ per common share)
Earnings per common
share $ 1.14 $ 1.11 $ 1.20 $ 1.20 $ 0.85
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