HALIFAX, Feb. 20 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net
earnings were $121.2 million for the year ended December 31, 2005, down from
$129.8 million in 2004.
The decrease in annual earnings reflects lower earnings at Emera's
largest subsidiary, Nova Scotia Power Inc. (NSPI), which earned $91.2 million
in 2005, compared to $107.3 million in 2004. NSPI's fuel costs were
approximately $71 million, or 23% higher year over year, due to higher coal
and oil prices. The related earnings impact was only partially offset by an
approximately 5% electricity rate increase implemented in the spring of 2005,
and the deferral of first quarter corporate taxes in advance of that rate
increase.
Emera's consolidated net earnings for the fourth quarter of 2005 were
$37.7 million, compared to $31.4 million for the fourth quarter of 2004.
Again, higher coal and oil prices increased fuel expense in NSPI by
approximately $16 million. This was offset by a revised agreement on natural
gas supply pricing, reached in November, which was more favourable than had
been estimated. It resulted in a $24 million adjustment to fuel expense for
2005, all of which was recorded in Q4.
Earnings per share were $1.11 for the year ended December 31, 2005,
compared to $1.20 in the prior year; and $0.34 for the fourth quarter of 2005,
compared to $0.30 in Q4, 2004.
"Rising fuel costs continue to have a major effect on the company," said
Chris Huskilson, President and Chief Executive Officer of Emera Inc. "The
issue of fuel costs was central to Nova Scotia Power's 2006 rate application.
A decision from the regulator is expected soon."
Bangor Hydro Electric (BHE), Emera's electricity transmission and
distribution utility in Maine, contributed $4.0 million to consolidated net
earnings in Q4, 2005, compared to $4.4 million in Q4, 2004; and $14.9 million
for the year ended December 31, 2005, compared to $18.5 million for 2004. The
lower earnings primarily reflect increases in depreciation rates, higher
NEPOOL transmission expenses, and the effect of a stronger Canadian dollar.
Emera's Other operations contributed $15.1 million to consolidated net
earnings for the year ended December 31, 2005, compared to $4.0 million in
2004. The addition of the Bear Swamp hydro-electric facility, foreign exchange
gains, and the capitalization of business development expenses related to the
Bear Swamp acquisition contributed to the earnings increase.
Consolidated cash used in operating activities was $36.3 million in Q4,
2005, compared to cash provided by operating activities of $62.9 million in
Q4, 2004, primarily due to changes in working capital.
About Emera Inc.
Emera Inc. (EMA-TSX) is an energy and services company with $4.0 billion
in assets. Electricity is Emera's core business. The company has two
wholly-owned regulated electric utility subsidiaries, Nova Scotia Power Inc.
and Bangor Hydro-Electric Company, which together serve 580,000 customers.
Nova Scotia Power supplies over 95% of the electric generation, transmission
and distribution in Nova Scotia. Bangor Hydro provides electricity
transmission and distribution service to 110,000 customers in eastern Maine.
Emera's other investments include a 12.9% interest in the Maritimes &
Northeast Pipeline and Emera Energy Services which manages energy assets on
behalf of third parties and provides related services. Visit Emera on the web
at www.emera.com.
Teleconference Call
Emera is holding a teleconference today at 11:30 AM Atlantic (10:30 AM
Eastern, 7:30 AM Pacific) to discuss the Q4, 2005 financial results. Analysts
and other interested parties wanting to participate in the call should dial
1-866-898-9626 (in Toronto 416-340-2216) at least 10 minutes prior to the
start of the call. No pass code is required. The teleconference will be
recorded. If you are unable to join the teleconference live, you can dial for
playback toll-free at 1-800-408-3053 (in Toronto 416-695-5800), access code
3174566 followed by the number sign. (available until midnight, Monday,
February 27, 2006). The teleconference will also be web cast live at
www.emera.com and available for playback for one year.
Forward Looking Information
This news release contains forward looking information. Actual future
results may differ materially. Additional financial and operational
information is filed electronically with various securities commissions in
Canada through the System for Electronic Document Analysis and Retrieval
(SEDAR).
Management's Discussion & Analysis
As at February 17, 2006
Management's Discussion and Analysis ("MD&A") provides a review of the
results of operations of Emera Inc. and its primary subsidiaries and
investments during the fourth quarter of 2005 relative to 2004, and the full
year 2005 relative to 2004 and to 2003, and its financial position at
December 31, 2005 relative to 2004. 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 subsidiary, Nova Scotia Power Inc.'s accounting policies are
subject to examination and approval by the Nova Scotia Utility and Review
Board. Emera's subsidiary, Bangor Hydro-Electric Company's accounting policies
are subject to examination and approval by the Maine Public Utilities
Commission and the Federal Energy Regulatory Commission. The rate-regulated
accounting policies of Nova Scotia Power and Bangor Hydro may differ from GAAP
for non rate-regulated companies.
Throughout this discussion, "Emera Inc." and "Emera" refer to Emera Inc.
and all of its consolidated subsidiaries and affiliates.
All amounts are in Canadian dollars ("CAD") except for the Bangor Hydro
section of the MD&A, which is reported in US dollars ("USD") unless otherwise
stated.
Additional information related to Emera, including the company's Annual
Information Form, can be found on SEDAR at www.sedar.com.
<<
CONSOLIDATED FINANCIAL HIGHLIGHTS
(millions of dollars,
except earnings Three months ended Year ended
per common share) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004 2003
-------------------------------------------------------------------------
Revenues $297.1 $286.5 $1,168.0 $1,134.2 $1,146.8
Net earnings from
continuing operations 37.7 30.7 122.1 127.6 128.2
Consolidated net earnings 37.7 31.4 121.2 129.8 129.2
Earnings per common share
- basic 0.34 0.30 1.11 1.20 1.20
Net cash (used in)
provided by operating
activities (36.3) 62.9 164.3 304.6 251.9
Cash dividends declared
per share 0.2225 0.22 0.89 0.88 0.86
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $580 million of assets serving 110,000
customers in eastern Maine. BHE's transmission operations are
regulated by the Federal Energy Regulatory Commission ("FERC"), and
its distribution operations are regulated by the Maine Public
Utilities Commission ("MPUC"). BHE is a cost of service utility, with
an alternate rate plan ("ARP") for its distribution operations.
The success of Emera's electric utilities is integral to the creation of
shareholder value, providing substantial earnings and cash flow to fund
dividends and reinvestment. The essential nature of the services provided, the
monopoly positions, and the regulated market structures means that NSPI and
BHE can generally be expected to produce relatively stable earnings streams,
within regulated ranges. Nova Scotia and Maine are mature electricity markets,
with annual demand growth of approximately 2%. Accordingly, Emera must look
beyond its existing regulated electricity business to supplement organic
growth.
Emera's plan for growth seeks to add energy infrastructure assets to its
portfolio. The company is focused on building on its core electricity
business, specifically in regulated transmission and distribution operations,
and low risk generation facilities. To this end, in 2005 Emera, in a 50-50
joint venture with Brookfield Power Corporation (formerly Brascan Power
Corporation), completed the acquisition of Bear Swamp, a 600 megawatt ("MW")
pumped storage hydro-electric generating facility in northern Massachusetts.
Consolidated Net Earnings History
(millions of dollars)
2005 2004 2003 2002 2001 2000
$121.2 $129.8 $129.2 $83.6 $114.2 $104.4
Earnings per Share History
(dollars)
2005 2004 2003 2002 2001 2000
$1.11 $1.20 $1.20 $0.85 $1.20 $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, 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 Three months ended Year ended
per common share) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004 2003
-------------------------------------------------------------------------
Electric revenue $287.3 $276.9 $1,125.9 $1,095.7 $1,104.1
Other 9.8 9.6 42.1 38.5 42.7
-------------------------------------------------------------------------
297.1 286.5 1,168.0 1,134.2 1,146.8
Fuel for generation and
purchased power 96.7 97.0 432.0 350.0 363.3
Operating, maintenance,
and general 61.9 62.6 248.2 245.2 258.6
Provincial, state, and
municipal taxes 11.8 11.4 48.4 46.3 40.8
Provincial tax deferral 0.4 - (4.5) - -
Depreciation 34.2 32.3 136.1 131.2 126.9
Regulatory amortization 2.9 6.8 19.4 26.1 18.2
Other (2.7) (2.8) (10.9) (10.2) (13.6)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 91.9 79.2 299.3 345.6 352.6
Interest 38.4 30.5 117.4 126.8 133.6
Amortization of
defeasance costs 3.3 3.8 13.2 15.1 16.7
Other income (8.0) - (8.0) - -
-------------------------------------------------------------------------
Earnings before income
taxes 58.2 44.9 176.7 203.7 202.3
Income taxes 19.0 10.8 53.5 62.7 60.9
Income taxes deferral (1.8) - (12.2) - -
-------------------------------------------------------------------------
Net earnings before
non-controlling interest 41.0 34.1 135.4 141.0 141.4
Non-controlling interest 3.3 3.4 13.3 13.4 13.2
-------------------------------------------------------------------------
Net earnings from
continuing operations 37.7 30.7 122.1 127.6 128.2
(Loss) earnings from
discontinued operations,
net of tax - 0.7 (0.9) 2.2 1.0
-------------------------------------------------------------------------
Net earnings applicable
to common shares $37.7 $31.4 $121.2 $129.8 $129.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share
- basic
Continuing operations $0.34 $0.29 $1.12 $1.18 $1.19
Discontinued operations - 0.01 (0.01) 0.02 0.01
-------------------------------------------------------------------------
$0.34 $0.30 $1.11 $1.20 $1.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share
- diluted
Continuing operations $0.34 $0.27 $1.10 $1.14 $1.14
Discontinued operations - 0.01 (0.01) 0.02 0.01
-------------------------------------------------------------------------
$0.34 $0.28 $1.09 $1.16 $1.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Unit Contributions
(millions of dollars,
except earnings Three months ended Year ended
per common share) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004 2003
-------------------------------------------------------------------------
Nova Scotia Power $34.0 $25.0 $91.2 $107.3 $112.1
Bangor Hydro-Electric 4.0 4.4 14.9 18.5 18.8
Other (0.3) 2.0 15.1 4.0 (1.7)
-------------------------------------------------------------------------
Consolidated net earnings $37.7 $31.4 $121.2 $129.8 $129.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic $0.34 $0.30 $1.11 $1.20 $1.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - diluted $0.34 $0.28 $1.09 $1.16 $1.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of 2005
Emera Inc.'s consolidated earnings increased $6.3 million to
$37.7 million in Q4, 2005 compared to $31.4 million for the same period in
2004. The earnings increase was substantially due to the finalization of
pricing terms of NSPI's natural gas supply contract in the quarter at better
than previously estimated pricing. Also contributing to the quarter over
quarter increase was a separate agreement with NSPI's gas supplier that
resulted in a net payment of $8.0 million. Emera's annual consolidated
earnings were $121.2 million in 2005 compared to $129.8 million in 2004 and
$129.2 million in 2003. Highlights of the changes are summarized in the
following table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Consolidated net earnings - 2003 $129.2
Increased electric revenue in NSPI,
reflecting volume growth 21.3
Increased fuel expense in NSPI due to
reduced gas sales margin and higher
coal costs in Q4 (25.3)
Increased provincial grants and taxes
in NSPI (6.1)
Increased depreciation in NSPI, reflecting
updated rates and capital investment (14.3)
Increased energy marketing margin 12.5
Decreased interest expense, reflecting
lower debt levels and interest rates 6.8
Adjustment to NSPI's and BHE's unbilled
revenue in 2003 13.2
Hurricane Juan operating expenses in 2003 6.0
Cessation of SOEP processing fees and
depreciation expense on sale of
asset in 2003 (5.7)
All other (7.8)
-------------------------------------------------------------------------
Consolidated net earnings - 2004 $31.4 $129.8
Increased electric revenue in NSPI due
to the 5.3% rate increase effective
April 1, 2005, partially offset by a
36 GWh decrease in volume for the year 5.2 28.1
Increased fuel expense in NSPI due to
higher commodity prices, changes in
generation mix partially offset by
increased hydro production (20.8) (84.3)
Decrease in fuel expense in NSPI due
to finalization of pricing terms of
NSPI's natural gas supply contract 23.8 -
Decrease in fuel expense in NSPI due to
increased gas resale margin 4.3 13.6
Increased operating expenses in NSPI due
to increased planned plant maintenance,
storm-related costs, and regulatory costs (2.4) (11.3)
Net payment from a gas supplier in NSPI 8.0 8.0
(Increased) decreased income taxes in NSPI
resulting from (higher) lower earnings (7.8) 13.7
Deferral of Q1, 2005 taxes in NSPI 1.4 16.7
Addition of Bear Swamp hydro-electric
facility earnings before interest & taxes 1.6 4.2
Reversal of foreign exchange gain,
recognized earlier in the year, due to
settlement of US denominated financial
obligations (5.9) -
Foreign exchange gains reflecting an
adjustment to refine prior years'
foreign exchange - 5.2
All other (1.1) (2.5)
-------------------------------------------------------------------------
Consolidated net earnings - 2005 $37.7 $121.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q4 basic earnings per share were $0.34 in 2005 compared to $0.30 in 2004;
and $1.11 for the full year 2005 compared to $1.20 in both 2004 and 2003.
SIGNIFICANT ITEMS
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 - which began in 2000 and runs until 2010 - calls for
up to approximately 61,000 MMBtus of natural gas per day to be supplied to
Nova Scotia Power, and was subject to a price re-determination as of
November 1, 2004. With both parties unable to agree on terms, the matter was
referred to arbitration. The two companies reached agreement prior to the
rendering of a decision by the arbitration panel. Throughout most of 2005,
while the initial contract discussions and later, the arbitration hearing
unfolded, 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 the year, all of which was recorded in Q4. 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 has been
recorded as other income in Q4.
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 were last set in 2002.
2004
There were no significant items in 2004.
2003
Unbilled revenue adjustment
The company recognizes electric revenues on the accrual basis, which
includes an estimate of electricity consumed by customers in the period but
billed subsequently ("unbilled revenue"). In 2003, the company improved its
process for estimating its unbilled revenue. The change resulted in one-time
reductions in unbilled revenue accruals with corresponding charges against
revenues as follows:
- NSPI $10.0 million ($6.5 million after-tax) in Q2, 2003
- BHE $3.2 million ($1.9 million after-tax) in Q3, 2003
Hurricane Juan
In Q3, 2003 Nova Scotia was struck by Hurricane Juan, a Category Two
hurricane causing extensive damage to Nova Scotia Power's transmission and
distribution system. The total cost of the hurricane to the company was
$12.6 million, specifically $4.0 million of net after-tax operating costs that
were recorded in Q3, 2003, and $8.6 million in capital costs.
Site restoration costs
Prior to 2003, Nova Scotia Power estimated and accrued site restoration
costs for the Glace Bay generating station. The costs to complete the
restoration were expected to be $3.8 million lower than estimated. Nova Scotia
Power reduced its provision accordingly, with a corresponding reduction in
depreciation expense in Q4, 2003.
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 122 MW
of renewable energy, substantially wind energy, under contract with
independent power producers, of which 57 MW are in service and the remainder
expected to be in operation in the next 18 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 1,600 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 cover prudently incurred costs of providing electricity service to
customers, and provide an appropriate return to investors. NSPI's allowed
regulated return on common equity ("ROE") range is 9.3% to 9.8%, with common
equity allowed to grow to 40% of the capital structure. Rates were last set
using 9.55% ROE with a common equity component of 37.5% of total
capitalization.
2005 Electricity Rate Increase
On March 31, 2005, the UARB granted NSPI an average rate increase of
approximately 5.3%, effective April 1, 2005. The rate decision increased
NSPI's electric revenues by approximately $25 million in 2005 compared to
2004. The decision also provided for full recovery of NSPI's $146.7 million
Section 21 income tax deposit over eight years, commencing in 2007. 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. The UARB also rejected NSPI's settlement proposal
to defer an additional $13 million of fuel costs to 2006.
The UARB made certain findings and directives concerning NSPI's fuel
procurement in its decision. On September 30, 2005, Nova Scotia Power filed a
report with the UARB outlining changes it has made to fuel procurement to
comply with the UARB's findings.
2006 Rate Application
In July 2005, Nova Scotia Power filed a general rate application
requesting an average 15% increase in electricity prices for 2006, primarily a
result of rising fuel commodity prices. In November, as a result of benefits
associated with the re-negotiated natural gas supply contract, NSPI reduced
its rate request to an average 13%.
The rate application also proposes increases to operating costs of
approximately $19 million to improve customer service, strengthen network
reliability and to implement new conservation and energy efficiency measures.
Hearings concluded in early December with a decision anticipated in Q1,
2006.
Review of 2005
NSPI Net Earnings
(millions of dollars,
except earnings Three months ended Year ended
per common share) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004 2003
-------------------------------------------------------------------------
Electric revenue $243.0 $237.8 $955.0 $926.9 $895.6
-------------------------------------------------------------------------
Fuel for generation and
purchased power 79.5 86.9 373.8 303.1 277.8
Operating, maintenance
and general 48.8 46.4 188.8 177.5 186.0
Provincial grants
and taxes 10.2 9.9 40.4 39.5 33.4
Provincial grants and
taxes deferral 0.4 - (4.5) - -
Depreciation 30.1 28.2 119.5 116.0 101.7
Regulatory amortization 1.5 1.5 6.2 6.2 6.2
Other (2.6) (2.5) (10.1) (10.4) (13.5)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 75.1 67.4 240.9 295.0 304.0
Interest 25.8 24.6 97.9 100.1 104.3
Amortization of
defeasance costs 3.3 3.8 13.2 15.1 16.7
Other income (8.0) - (8.0) - -
-------------------------------------------------------------------------
Earnings before income
taxes 54.0 39.0 137.8 179.8 183.0
Income taxes 18.5 10.7 45.5 59.2 57.8
Income taxes deferral (1.8) - (12.2) - -
-------------------------------------------------------------------------
Earnings before preferred
dividends 37.3 28.3 104.5 120.6 125.2
Preferred dividends 3.3 3.3 13.3 13.3 13.1
-------------------------------------------------------------------------
Contribution to
consolidated
net earnings $34.0 $25.0 $91.2 $107.3 $112.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share $0.30 $0.23 $0.83 $0.99 $1.04
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's contribution to consolidated net earnings was $34.0 million in Q4,
2005, compared to $25.0 million in Q4, 2004. The earnings increase was
substantially due to the finalization of pricing terms of NSPI's natural gas
supply contract in the quarter at better than previously estimated pricing.
Also contributing to the quarter over quarter increase was a separate
agreement with NSPI's gas supplier that resulted in a net payment of
$8.0 million. Annual contribution to consolidated net earnings was
$91.2 million in 2005 compared to $107.3 million in 2004 and $112.1 million in
2003. Highlights of the earnings changes are summarized in the following
table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2003 $112.1
Increased electric revenues, largely
reflecting volume growth 21.3
Increased fuel expense due to reduced gas
sales margin and higher coal costs in Q4 (25.3)
Increased provincial grants and taxes (6.1)
Increased depreciation, reflecting
updated rates, and capital investment (14.3)
Adjustment to unbilled revenue in 2003 10.0
Hurricane Juan operating expenses in 2003 6.0
All other 3.6
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2004 $25.0 $107.3
Increased electric revenue due to the 5.3%
rate increase effective April 1, 2005,
partially offset by a 36 GWh decrease
in sales volume for the year 5.2 28.1
Increased fuel expense due to higher
commodity prices, and changes in generation
mix partially offset by increased hydro
production (20.8) (84.3)
Decrease in fuel expense due to
finalization of pricing terms of NSPI's
natural gas supply contract 23.8 -
Decrease in fuel expense due to increased
gas resale margin 4.3 13.6
Increased operating expenses reflecting
increased planned plant maintenance,
storm-related costs, and regulatory costs (2.4) (11.3)
Increased depreciation due to capital
investment (1.9) (3.5)
In Q4, increased interest due to foreign
exchange losses; year ended December 31,
decreased interest due to lower rates (1.2) 2.2
Net payment from a gas supplier 8.0 8.0
(Increased) decreased income taxes
resulting from (higher) lower earnings (7.8) 13.7
Deferral of Q1, 2005 taxes 1.4 16.7
All other 0.4 0.7
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2005 $34.0 $91.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q4 Electric Sales Volume Q4 Electric Sales Revenues
(Gigawatt hours ("GWh")) (millions of dollars)
----------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
----------------------------------- ------------------------------------
Residential 999 1,052 1,049 Residential $104.2 $103.4 $102.8
Commercial 728 754 744 Commercial 65.3 66.3 64.6
Industrial 1,020 1,068 1,037 Industrial 58.6 55.3 53.5
Other 144 153 119 Other 14.9 12.8 10.3
----------------------------------- ------------------------------------
Total 2,891 3,027 2,949 Total $243.0 $237.8 $231.2
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
YTD Electric Sales Volume YTD Electric Sales Revenues
(GWh) (millions of dollars)
----------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
----------------------------------- ------------------------------------
Residential 4,000 4,039 3,819 Residential $411.4 $402.9 $375.8
Commercial 3,004 2,965 3,001 Commercial 263.6 258.3 253.4
Industrial 4,197 4,196 4,091 Industrial 235.1 222.5 218.5
Other 436 473 586 Other 44.9 43.2 47.9
----------------------------------- ------------------------------------
Total 11,637 11,673 11,497 Total $955.0 $926.9 $895.6
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Q4 Average Revenue / Megawatt hour
("MWh")
-----------------------------------
2005 2004 2003
-----------------------------------
Dollars per
MWh $84 $79 $78
-----------------------------------
-----------------------------------
YTD Average Revenue / MWh
-----------------------------------
2005 2004 2003
-----------------------------------
Dollars per
MWh $82 $79 $78
-----------------------------------
-----------------------------------
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, which apply to approximately 20% of NSPI sales volume;
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 in Nova Scotia, 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 $5.2 million to $243.0 million in Q4, 2005
from $237.8 million for the same period in 2004. Revenue increases are
substantially due to the April 1, 2005 rate increase partially offset by
reduced sales volume due to warmer weather in Q4, customer conservation
efforts, and the temporary shut down of a large industrial customer for a
portion of December 2005.
For the year ended December 31, 2005, electric revenues increased
$28.1 million to $955.0 million in comparison to $926.9 million in 2004. The
revenue increase is due to the reasons noted above.
For the year ended December 31, 2004, electric revenues increased
$31.3 million, to $926.9 million from $895.6 million in 2003. Of the
difference, $10.0 million relates to a charge against revenue in the 2003
comparative amounts, due to an adjustment to the company's unbilled revenue
accrual. In addition to normal growth, a cold Q1, 2004 increased sales
volumes. Export sales volumes were lower, as available capacity was used to
service in-province load.
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 57 megawatts in service contracted with
independent power producers. NSPI meets the planning criteria for reserve
capacity established by the Maritime Control Area, and therefore meets the
Northeast Power Coordinating Council criteria.
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 affect 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, including 200 MW
of which is economically interruptible.
- 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's generating capacity utilization was 78% in 2005 compared to 82% in
2004. The change is largely due to the completion of two planned turbine
inspections as part of NSPI's maintenance and life cycle management program
for generation assets.
NSPI Thermal Capacity Utilization
2005 2004 2003 2002 2001 2000
78% 82% 78% 77% 77% 74%
NSPI facilities continue to perform highly among the top ten units in
Canada for capacity related performance indicators. In the most recent
Canadian Electrical Association rankings, NSPI units hold five of the top ten
positions in Canada including Trenton 6 in first place in 2004. Point Tupper
ranked Number 1 in the previous year.
NSPI Generating Capacity Availability
2005 2004 2003 2002 2001 2000
90% 92% 91% 91% 91% 88%
Fuel Expense
Q4 Production Volume YTD Production Volume
(GWh) (GWh)
----------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
----------------------------------- ------------------------------------
Coal & Coal &
petcoke 2,280 2,471 2,398 petcoke 9,116 9,490 9,219
Natural gas 32 26 65 Natural gas 194 97 119
Oil 442 433 288 Oil 1,581 1,698 1,536
Renewable 308 265 276 Renewable 1,063 889 1,080
Purchased Purchased
power 126 91 111 power 529 391 375
----------------------------------- ------------------------------------
Total 3,188 3,286 3,138 Total 12,483 12,565 12,329
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Purchased power includes 29 GWh of Purchased power includes 83 GWh of
wind power in Q4, 2005 wind power in 2005.
Q4 Average Unit Fuel Costs
-----------------------------------
2005 2004 2003
-----------------------------------
Dollars per
MWh $25 $26 $20
-----------------------------------
-----------------------------------
YTD Average Unit Fuel Costs
-----------------------------------
2005 2004 2003
-----------------------------------
Dollars per
MWh $30 $24 $23
-----------------------------------
-----------------------------------
Coal is NSPI's dominant fuel source, supplying approximately 50% of the
company's annual generation. Petroleum coke ("petcoke") fuels approximately
25% 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.
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, 2005, fuel for generation and
purchased power was $79.5 million, compared to $86.9 million in Q4, 2004. For
the year ended December 31, 2005, fuel for generation and purchased power was
$373.8 million compared to $303.1 million in 2004 and $277.8 million in 2003.
Highlights of the changes are summarized in the following table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Fuel for generation and purchased
power - 2003 $277.8
Lower net proceeds from resale of
natural gas 32.0
Increased production 16.9
Decreased renewable production volumes 11.9
Commodity pricing, including
favourable exchange rates (16.7)
Decreased export volumes (11.4)
All other (7.4)
-------------------------------------------------------------------------
Fuel for generation and purchased
power - 2004 $86.9 $303.1
Commodity pricing increase 29.5 91.1
Higher net proceeds from resale of
natural gas (4.3) (13.6)
Finalization of pricing terms of
NSPI's natural gas supply contract (23.8) -
Changes in generation mix 5.8 12.2
Increase in hydro production volumes (2.2) (11.7)
All other (12.4) (7.3)
-------------------------------------------------------------------------
Fuel for generation and purchased
power - 2005 $79.5 $373.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 - which began in 2000 and runs until 2010 - calls for
up to approximately 61,000 MMBtus of natural gas per day to be supplied to
Nova Scotia Power, and was subject to a price re-determination as of
November 1, 2004. With both parties unable to agree on terms, the matter was
referred to arbitration. The two companies reached agreement prior to the
rendering of a decision by the arbitration panel. Throughout most of 2005,
while the initial contract discussions and later, the arbitration hearing
unfolded, 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 the year, all of which was recorded in Q4. 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 has been
recorded as other income in Q4.
Operating, Maintenance & General Expenses
NSPI's operating, maintenance and general expenditures ("OM&G") were
$48.8 million in Q4, 2005 compared to $46.4 million in Q4, 2004. The increase
of $2.4 million is primarily a result of adjustments to the allowance for
doubtful accounts and increased regulatory costs.
For the year ended December 31, 2005, NSPI's OM&G expenditures were
$188.8 million, compared to $177.5 million in 2004 and $186.0 million for
2003. OM&G expenditures increased $11.3 million in 2005 over 2004 due to
increased planned plant maintenance, storm-related costs and higher regulatory
costs. OM&G expenditures decreased $8.5 million in 2004 from 2003 levels
primarily as a result of lower labour and materials costs.
Provincial Grants and Taxes
NSPI pays annual grants to the Province of Nova Scotia, in lieu of all
municipal taxation other than deed transfer tax.
Provincial grants and taxes increased $0.3 million in Q4, 2005, and
$0.9 million for the year ended December 31, 2005 reflecting inflationary
adjustments. For the year ended December 31, 2004, the provincial grants and
taxes increased $6.1 million over 2003, reflecting a $4.6 million increase in
NSPI's annual provincial grants, and an increase in the provincial capital tax
rate from 0.25% to 0.3%, effective April 1, 2004.
In Q1, 2005 the UARB agreed to allow NSPI to defer these and other taxes
not reflected in rates for the period from January 1, 2005 until April 1,
2005, the date when new rates became effective. As a result, NSPI deferred
$4.5 million of provincial grants and taxes to March 31, 2005. The
amortization period is pending approval by the UARB.
Depreciation
NSPI's depreciation expense increased $1.9 million in Q4, 2005 to
$30.1 million compared to $28.2 million in Q4, 2005, primarily due to
increased plant-in-service.
For the year ended December 31, 2005 depreciation expense increased
$3.5 million to $119.5 million compared to $116.0 million in 2004, for the
reason noted above. The 2004 amount is $14.3 million higher than 2003,
reflecting the change in depreciation rates approved by the UARB in its 2003
depreciation order, and increased plant-in-service.
Regulatory Amortization
The Glace Bay generating station has been demolished and returned to an
industrial Greenfield site, and is being amortized at a minimum annual rate of
$6.2 million. The amount remaining to be written off is $12.9 million.
Interest
Interest expense increased $1.2 million, to $25.8 million in Q4, 2005,
compared to $24.6 million in Q4, 2004 due to foreign exchange losses on
US dollar denominated working capital, offset by a gain on an interest rate
derivative.
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.
For the year ended December 31, 2004, interest expense decreased
$4.2 million, to $100.1 million compared to $104.3 million in 2003. This
decrease is due to the refinancing of a $140 million mid-term note with
short-term debt in 2004.
The company manages exposure to interest rate risk through a combination
of fixed and floating borrowing, and hedging. Interest rate swaps are the
principal instrument used to hedge interest rate risk.
Other Income
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 renegotiation
of certain 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 (0.288%), large corporations
tax (0.175%), corporate income tax (38.12%) and Part VI.1 tax relating to
preferred dividends (40%).
NSPI has a $146.7 million regulatory asset related to pre-2003 income
taxes that have been paid, but not yet recovered from customers. This
circumstance arose when NSPI claimed deductions that were ultimately
disallowed by a decision of the Supreme Court of Canada. The UARB has approved
the amortization and recovery of this regulatory asset over eight years,
commencing in 2007.
In Q1, 2005 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. As a result, NSPI deferred $12.2 million of federal
capital taxes and income taxes reflecting increases in these taxes since rates
were last set in 2002. The amortization period is pending approval by the
UARB.
Outlook
NSPI's earnings outlook for 2006 is substantially dependant on the
outcome of the 2006 rate decision, expected in Q1, 2006. The magnitude of any
approved increase, as well as timing of the implementation will affect
revenues and could have a material impact on earnings.
Electricity sales volume (load) is expected to be lower in 2006 than in
2005, due to warmer weather in Q1, the temporary shut-down of a large
industrial customer and customer conservation effects. Fuel costs are expected
to increase primarily due to higher commodity prices and an increase in the
amount of higher cost, lower sulphur coal in the fuel mix to meet provincial
environmental regulations. These higher costs will be partially offset by the
expected reduction in load noted above.
Other costs of NSPI are generally expected to remain consistent with
normalized 2005 levels, with additional investments expected to be made in
vegetation management, storm response initiatives and energy conservation
management. NSPI has also requested an increase in depreciation expense in its
2006 rate application, to implement approved increases flowing from its recent
depreciation study.
Debt Management
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.
In 2004, a $140 million 7.3% mid-term note matured and was refinanced
with short-term debt.
The weighted average coupon rate on NSPI's outstanding medium-term and
debenture notes at December 31, 2005, was 6.83% (2004 - 7.32%). Approximately
41% of the debt matures over the next ten years; 55% matures between 2016 and
2036; and $50.0 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 4.96% as of December 31, 2005 (2004 - 5.14%).
NSPI has established the following available credit facilities:
Maximum
(millions of dollars) Maturity amount
-------------------------------------------------------------------------
Short-term
Commercial paper, with 100% backup line
of credit 1 Year Revolving $400.0
Operating credit facility 3 Year Revolving $100.0
-------------------------------------------------------------------------
NSPI has the following available credit ratings:
DBRS S&P Moodys
-------------------------------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------
Long-term
corporate A(low) A(low) BBB+ BBB+ N/A N/A
Senior
unsecured
debt A(low) A(low) BBB+ BBB+ Baa1 Baa1
Preferred
stock Pfd-2(low) Pfd-2(low) P-2(low) P-2(low) N/A N/A
Commercial
paper R-1(low) R-1(low) A-1(low) A-1(low) P-2(Baa) P-2(Baa)
-------------------------------------------------------------------------
On July 5, 2005, Standard & Poor's Rating Services revised its outlook on
Nova Scotia Power to negative from stable, citing fuel cost recovery concerns.
On July 6, 2005, the Dominion Bond Rating Service confirmed NSPI's ratings as
A (low) and the commercial paper rating as R-1 (low). On October 11, 2005,
Moody's Investor Services revised its outlook on Nova Scotia Power from stable
to negative citing fuel cost recovery and regulatory uncertainty.
Based on the company's available credit and credit ratings, and past
experience in public financing since privatization, NSPI expects to have
access to capital when needed.
Outlook
An NSPI medium-term note ("MTN") of $40 million bearing interest of
5.20%, maturing in 2029 is redeemable at the option of the holder in April
2006. If not redeemed, the interest rate on the MTN increases to 6.28% until
maturity.
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
900 kilometers of transmission facilities, and 7,000 kilometers of
distribution facilities. BHE has a workforce of approximately 230 people.
In addition to T&D assets, BHE has substantial 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 unamortized portion on its loss on the sale of its
investment in the Seabrook nuclear facility; and the costs associated with the
buy-out/restructure of above-market power purchase contracts. 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 $80 million at December 31, 2005, or 15% of BHE's net
asset base.
Approximately 55% of BHE's electric rate represents distribution service,
30% relates to stranded cost recoveries, and 15% 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, or 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.
On February 25, 2005, the MPUC approved BHE's stranded cost rates for the
three-year period March 1, 2005 to February 29, 2008, providing an allowed
return on equity of 10% on BHE's stranded assets. The stranded cost rates were
reduced to reflect the completion of a major regulatory amortization, and
increases in the rate at which BHE's power purchases under long-term power
supply agreements will be resold to a third party. Accordingly, the impact on
net earnings is expected to be minimal.
Transmission rates are set by the FERC annually on July 1, based on the
prior year's revenue requirement. The current allowed ROE for transmission
operations is 11.25%.
Review of 2005
BHE Net Earnings
(millions of dollars,
except earnings Three months ended Year ended
per common share) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004 2003
-------------------------------------------------------------------------
T&D revenues $25.9 $29.7 $105.5 $116.4 $115.1
Resale of purchased power 4.0 1.9 13.6 10.6 26.0
-------------------------------------------------------------------------
Total electric revenue 29.9 31.6 119.1 127.0 141.1
Fuel for generation and
purchased power 9.7 8.4 33.6 35.0 54.4
Operating, maintenance
and general 7.7 8.7 31.2 31.7 33.1
Property taxes 0.8 1.1 4.9 4.8 5.0
Depreciation 3.2 3.1 12.4 10.9 9.6
Regulatory amortization 1.1 4.3 10.8 15.2 10.4
Other (0.8) (1.1) (3.9) (3.3) (3.8)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 8.2 7.1 30.1 32.7 32.4
Interest 2.6 2.5 10.0 10.3 10.2
-------------------------------------------------------------------------
Earnings before income
taxes 5.6 4.6 20.1 22.4 22.2
Income taxes 2.2 0.8 7.8 8.0 8.9
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings - US $ $3.4 $3.8 $12.3 $14.4 $13.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings - Canadian $ $4.0 $4.4 $14.9 $18.5 $18.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share
- Canadian $ $0.04 $0.04 $0.14 $0.17 $0.17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted
average foreign exchange
rate - Canadian/US $ 1.17 1.22 1.21 1.30 1.42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was $3.4 million
in Q4, 2005 compared to $3.8 million in Q4, 2004. For the year ended
December 31, 2005, Bangor Hydro's contribution to consolidated net earnings
was $12.3 million, compared to $14.4 million in 2004 and $13.3 million in
2003. Highlights of the earnings changes are summarized in the following
table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2003 $13.3
Adjustment to the company's unbilled
revenue in 2003 2.7
Increased revenues due to higher
energy sales volume 1.8
Decrease in labour costs 1.5
Increased depreciation expense due
to depreciation study impacts (1.2)
Write-off in Q2, 2004 of deferred
costs disallowed in rates (1.1)
All other (2.6)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2004 $3.8 $14.4
(Decreased) increased energy sales volume (0.3) 1.8
Increased depreciation expense,
reflecting new depreciation study (0.1) (1.6)
2004 stranded cost purchased power expense
less than amount used in setting rates (0.2) (1.1)
Decreased (increased) NEPOOL related
transmission expenses 0.3 (0.9)
Write-off in Q2, 2004 of deferred costs
disallowed in rates - 1.1
All other (0.1) (1.4)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2005 $3.4 $12.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was
$4.0 million CAD in Q4, 2005 compared to $4.4 million CAD in Q4, 2004, due to
the Canadian dollar equivalent of the variances discussed above and the
$0.2 million impact of the stronger Canadian dollar. For the year ended
December 31, 2005, net earnings contributed by Bangor Hydro was
$14.9 million CAD compared to $18.5 million CAD for 2004 and $18.8 million CAD
for 2003, due to the Canadian dollar equivalent of the variances discussed
above and the $1.0 million impact of the stronger Canadian dollar in 2005 and
$1.8 million impact of the stronger Canadian dollar in 2004.
Electric Revenue
Q4 Electric Sales Volume Q4 Electric Sales Revenues
(GWh) (millions of US dollars)
----------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
----------------------------------- ------------------------------------
Residential 157 156 147 Residential $13.0 $14.6 $13.9
Commercial 147 150 149 Commercial 9.0 10.4 10.4
Industrial 100 102 89 Industrial 2.8 3.6 3.8
Other 3 3 3 Other 1.1 1.1 1.6
----------------------------------- ------------------------------------
Total 407 411 388 Total $25.9 $29.7 $29.7
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
YTD Electric Sales Volume YTD Electric Sales Revenues
(GWh) (millions of US dollars)
----------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
----------------------------------- ------------------------------------
Residential 603 594 572 Residential $51.1 $56.0 $53.5
Commercial 610 603 585 Commercial 37.0 42.1 41.1
Industrial 404 359 359 Industrial 12.4 14.2 15.4
Other 12 12 12 Other 5.0 4.1 5.1
----------------------------------- ------------------------------------
Total 1,629 1,568 1,528 Total $105.5 $116.4 $115.1
----------------------------------- ------------------------------------
----------------------------------- ------------------------------------
Q4 Average Revenue / MWh
-----------------------------------
2005 2004 2003
-----------------------------------
Dollars per
MWh $64 $72 $76
-----------------------------------
-----------------------------------
YTD Average Revenue / MWh
-----------------------------------
2005 2004 2003
-----------------------------------
Dollars per
MWh $65 $74 $75
-----------------------------------
-----------------------------------
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 $3.8 million in Q4, 2005, to $25.9 million compared to
$29.7 million in Q4, 2004. For the year ended December 31, 2005, T&D electric
revenues were $105.5 million compared to $116.4 million for 2004 and
$115.1 million in 2003. Highlights of the changes are summarized in the
following table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
T&D revenues - 2003 $115.1
Increased energy sales volume 1.8
Unbilled revenue adjustment in Q3, 2003 2.7
Lower special contract rate for
large customer (1.1)
All other (2.1)
-------------------------------------------------------------------------
T&D revenues - 2004 $29.7 $116.4
Stranded cost rate reduction on
March 1, 2005 (3.5) (13.0)
(Decreased) increased energy
sales volume (0.3) 1.8
All other - 0.3
-------------------------------------------------------------------------
T&D revenues - 2005 $25.9 $105.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Increases to industrial volumes year to date had a minimal impact on
sales revenues due to lower unit pricing.
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 including a large contract that ended in
February 2004. Power purchased under these arrangements is resold to a third
party at market rates. The cessation of the contract in February 2004 was the
primary reason for the decrease in resale of purchased power and fuel for
generation and purchased power in 2004. Resale of purchased power increased in
2005 due to an increase in the rate at which BHE's power purchases are resold
to a third party. Also affecting purchased power expense in 2005 was a
$0.9 million increase in NEPOOL related transmission costs.
Operating, Maintenance and General Expenses
Operating expenses were $7.7 million in Q4, 2005 compared to $8.7 million
in 2004. For the year ended December 31, 2005, BHE's operating expenses were
$31.2 million compared to $31.7 million in 2004 and $33.1 million in 2003. The
changes are primarily due to reduced labour costs.
Depreciation
Depreciation expense increased by $0.1 million in Q4, 2005 compared to
Q4, 2004; increased $1.5 million in 2005 relative to 2004; and increased
$1.3 million in 2004 relative to 2003, due principally to the effect of plant
additions. The results of BHE's depreciation study, completed in 2004, are
also included in the results.
Regulatory Amortization
Amortization expense was $3.2 million lower in Q4, 2005 at $1.1 million,
compared to $4.3 million in Q4, 2004 reflecting new stranded cost
amortization, which started March 1, 2005.
For the year ended December 31, 2005 amortization expense was
$10.8 million, compared to $15.2 million in 2004 and $10.4 million in 2003.
The decrease in 2005 reflects the new stranded cost amortization, while the
increase in 2004 reflects the completion of the amortization of several
regulatory liabilities in Q1, 2004, offset somewhat by reduced stranded cost
amortization.
Interest
BHE's interest expense increased to $2.6 million in Q4, 2005 from
$2.5 million in Q4, 2004, and decreased to $10.0 million in 2005 from
$10.3 million in 2004 and $10.2 million in 2003. The decrease in annual
interest expense is due primarily to lower rates on debt refinanced, offset by
the impact of increased short-term borrowings and higher interest rates on
short-term borrowings.
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).
Debt Management
The weighted-average coupon rate on Bangor Hydro's long-term debt
outstanding at December 31, 2005 was 7.18% (2004 - 7.13%). Approximately 57%
of the debt matures over the next 13 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 5.55% as of
December 31, 2005 (2004 - 4.94%).
Bangor Hydro has established the following credit facilities:
Maximum
(millions of US dollars) amount
-------------------------------------------------------------------------
Short-term
Unsecured revolving facility $60.0
Operating line of credit $10.0
------------------------------------------------------------------------
During 2003, Bangor Hydro refinanced all of its public debt privately,
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.
Regulatory Matters
When Emera acquired Bangor Hydro in 2001, it became a registered public
utility holding company under the Public Utility Holding Company Act of 1935
("PUHCA"). PUHCA was administered by the US Securities and Exchange Commission
("SEC"). In the normal course of regulating registered public utility holding
companies, the SEC audited and/or reviewed each registrant's compliance with
PUHCA approximately once every five years. The SEC's review of Emera began in
the fall of 2004. By letter dated September 25, 2005 the staff of the SEC
indicated that Emera was in compliance with PUHCA, pending reallocation of
certain costs among companies in the Emera group. The proposed reallocations
are not material to Emera or any individual Emera subsidiary.
PUHCA has been repealed, effective February 8, 2006, under the
Domenici-Barton Energy Policy Act of 2005. As of that date, Emera ceased to be
regulated as a registered holding company under PUHCA. The Energy Policy Act
lodged certain new powers over companies that own electric and gas public
utility companies with the US FERC.
Outlook
Bangor Hydro net earnings for 2006 are expected to be marginally higher
than 2005.
The Northeast Reliability Interconnect, Bangor Hydro's proposed new
transmission line linking New Brunswick and Maine, achieved a milestone in
2005, with the receipt of its Certificate of Public Convenience and Necessity
from the Maine Public Utilities Commission. In January 2006, BHE received the
outstanding environmental permits from the State and Federal Governments.
Management continues to expect to have the line in service in late 2007.
OTHER
All activities of Emera other than its two regulated electric utilities
are incorporated in Other, including:
- Emera Energy Services, which manages energy assets on behalf of third
parties and provides related energy management services. Emera Energy
Services operates with minimal day-to-day commodity risk exposure.
- A 12.9% interest in the $2 billion, 1,300 kilometre Maritimes &
Northeast Pipeline ("M&NP") that transports Nova Scotia's offshore
natural gas to markets in Maritime Canada and the northeastern
United States.
- Bear Swamp, a 50-50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts, which was acquired
on May 24, 2005, as discussed below.
- Certain corporate-wide functions such as executive management,
strategic planning, treasury services, tax planning, business
development, and corporate governance; and financing for the
corporation's business outside of its regulated electric utilities.
Sale of Assets of Emera Fuels
Effective September 30, 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 approximately $20 million). The reduction in annual after-tax net
earnings and cash provided by operating activities is expected to be
immaterial.
Acquisition
On May 24, 2005 Emera and Brookfield Power Corporation (formerly Brascan
Power Corporation), in a 50-50 joint venture, completed the acquisition of
Bear Swamp, a 600 MW pumped storage hydro-electric facility in northern
Massachusetts. Emera's share of the purchase price was $61.2 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.
A second proposed joint venture acquisition, the 49 MW Bellows Falls
hydro-electric facility, did not receive the required regulatory approval.
Emera's escrow deposit was returned in Q4, 2005.
Review of 2005
Other net earnings
(millions of dollars,
except earnings Three months ended Year ended
per common share) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004 2003
-------------------------------------------------------------------------
Energy marketing margin $5.5 $6.7 $24.7 $24.2 $11.7
Electric revenue 9.2 - 26.5 - -
M&NP equity earnings 1.7 1.2 6.5 6.2 9.6
SOEP processing fees - - - - 16.3
-------------------------------------------------------------------------
Total revenue 16.4 7.9 57.7 30.4 37.6
Purchased power 5.9 - 17.7 - -
Operating maintenance
and general 5.4 5.1 21.7 20.8 19.1
Business development (1.3) 0.5 (0.2) 5.7 8.2
Depreciation 0.4 0.4 1.7 1.2 11.7
Other (1.1) (1.6) (5.2) (5.6) (4.2)
-------------------------------------------------------------------------
Earnings before interest
and income taxes 7.1 3.5 22.0 8.3 2.8
Interest 9.5 2.9 7.4 13.2 14.9
-------------------------------------------------------------------------
Earnings before income
taxes (2.4) 0.6 14.6 (4.9) (12.1)
Income taxes (2.1) (0.7) (1.4) (6.7) (9.4)
-------------------------------------------------------------------------
Net earnings from
continuing operations (0.3) 1.3 16.0 1.8 (2.7)
(Loss) earnings from
discontinued operations,
net of tax - 0.7 (0.9) 2.2 1.0
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings $(0.3) $2.0 $15.1 $4.0 $(1.7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per share $- $0.02 $0.14 $0.04 $(0.01)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The contribution of Other operations to consolidated net earnings
decreased $2.3 million quarter over quarter. For the year ended December 31,
2005, Other operations contributed $15.1 million to consolidated net earnings
compared to $4.0 million in 2004 and a loss of $1.7 million in 2003.
Highlights of the changes are summarized in the following table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2003 $(1.7)
Cessation of SOEP processing fees
on sale of asset (16.3)
Increase in energy marketing margin 12.5
Cessation of SOEP depreciation expense
on sale of asset 10.6
All other (1.1)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2004 $2.0 $4.0
(Decreased) increased energy marketing
margin as a result of (decreased)
increased marketing opportunities
and mark-to-market gains on longer
term contracts (1.2) 0.5
Addition of Bear Swamp hydro-electric
facility earnings before interest
& taxes 1.6 4.2
Reversal of foreign exchange gain,
recognized earlier in the year,
due to settlement of US denominated
financial obligations (5.9) -
Increased foreign exchange gains
reflecting an adjustment to refine
prior years' foreign exchange - 5.2
Lower (higher) income taxes due to
lower (higher) earnings 1.4 (5.3)
Capitalization of previously expensed
business development costs to the
Bear Swamp cost of net assets purchased 2.5 2.5
Loss on disposition of Emera Fuels,
net of tax - (1.6)
Write-off of Greyhawk Gas Storage joint
venture in Q1, 2004 - 1.9
All other (0.7) 3.7
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2005 $(0.3) $15.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Energy Marketing Margin
Emera Energy Services net margin decreased quarter over quarter to
$5.5 million in Q4, 2005, from $6.7 million in Q4, 2004 as a result of
decreased marketing opportunities.
For the year ended December 31, 2005 net margin was $24.7 million
compared to $24.2 million in 2004 and $11.7 million in 2003 due to increased
marketing opportunities and mark-to-market gains on longer term contracts in
2005.
Electric Revenue and Purchased Power
Electric revenue and purchased power represent Emera's pro-rata share of
electric revenue and purchased power from Bear Swamp since the date of
acquisition on May 24, 2005.
Equity Earnings
Equity earnings from the Maritimes & Northeast Pipeline were $1.7 million
in Q4, 2005, compared to $1.2 million for the same period in 2004. The
increase is primarily due to increases in tolls collected for the
US operations.
M&NP applied for new rates in 2004 and a decision is expected in Q1,
2006. In the interim, since January 1, 2005, M&NP was permitted to collect
proposed rates from customers. In the event approved rates are lower than
proposed, any excess will be returned to customers. On June 28, 2005 M&NP
submitted an offer of settlement to the FERC. The company has recognized its
best estimate of equity earnings based on the terms of the proposed
settlement. The rate decision will also impact energy marketing margin in
Emera Energy Services. The decision from the FERC is expected in Q1, 2006.
For the year ended December 31, 2005 M&NP equity earnings were
$6.5 million compared to $6.2 million in 2004. Increases in the tolls
collected for the US operations have been offset by the write off of
previously deferred costs for pipeline expansion on the US pipeline, and the
$0.1 million impact of the stronger Canadian dollar on the US portion of the
pipeline.
For the year ended December 31, 2004, equity earnings decreased
$3.4 million to $6.2 million compared to $9.6 million in 2003, reflecting
performance on the US component of the pipeline due to lower volumes, higher
operating costs associated with the Phase III expansion (not reflected in
rates at that time) and the $0.1 million impact of a stronger Canadian dollar.
Business Development
Business development recognized a $1.3 million cost recovery in Q4, 2005,
compared to a $0.5 million expense in Q4, 2004 due primarily to the
capitalization in Q4, 2005 of $2.5 million of previously expensed business
development costs to the Bear Swamp cost of net assets purchased.
For the year ended December 31, 2005, business development recognized a
$0.2 million cost recovery compared to a $5.7 million expense for the same
period in 2004, reflecting the capitalization referred to above; and the
write-off in Q1, 2004 of Emera's $1.9 million investment in the Greyhawk Gas
Storage joint venture, a portion of which was subsequently recovered in Q1,
2005. Business development expenses for 2004 were down $2.5 million from
$8.2 million in 2003 reflecting the streamlining of business development
activities.
Interest
Interest expense was $9.5 million in Q4, 2005 compared to $2.9 million in
Q4, 2004 largely as a result of the reversal of foreign exchange gains
recognized earlier in the year on the settlement of USD financial obligations,
as expected.
For the year ended December 31, 2005 interest was $7.4 million compared
to $13.2 million in 2004. The difference was substantially due to an
accounting adjustment required to refine prior years' foreign exchange
recognized on US denominated obligations. Interest expense was $1.7 million
lower in 2004 than in 2003, reflecting lower rates on short-term debt
refinanced.
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 impacted by withholding taxes paid on cross-border
dividends and interest, completion of prior years' tax returns, and corporate
tax sharing agreements.
Debt Management
In Q4 2005, Emera amended its operating and acquisition credit
facilities. The operating facility increased from $150 million to $200 million
and US subsidiaries were added as US borrowers.
Emera has established the following credit facilities outside its
regulated electric utilities:
Maximum
(millions of dollars) Maturity amount
-------------------------------------------------------------------------
Short-term
Operating credit facility 1 Year Revolving $200.0
Acquisition credit facility 1 Year Revolving $400.0
-------------------------------------------------------------------------
Emera has the following available credit ratings:
DBRS S&P Moodys
-------------------------------------------------------------------------
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------
Long-term
corporate BBB (high) BBB (high) BBB+ BBB+ N/A N/A
Senior
unsecured
debt BBB (high) BBB (high) BBB BBB Baa2 Baa2
-------------------------------------------------------------------------
In 2005, S&P and Moody's revised their outlook for Emera from stable to
negative citing Nova Scotia Power fuel cost recovery concerns and regulatory
uncertainty.
On a consolidated basis, Emera's target percentage of debt to total
capitalization is 50%-55%, of which 10%-15% 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
As at December 31
(millions of dollars)
-------------------------------------------------------------------------
2005 2004 2003
-------------------------------------------------------------------------
Total assets $3,996.2 $3,949.2 $3,890.9
Total long-term liabilities $2,123.6 $2,118.8 $1,797.3
-------------------------------------------------------------------------
Significant changes in the consolidated balance sheets between
December 31, 2005 and December 31, 2004 include:
- $12.4 million decrease in restricted cash reflecting lower posted
margin in Emera Energy Services.
- $55.7 million increase in accounts receivable, reflecting higher
pricing for trading activity in Emera Energy Services, and increased
electricity prices in Nova Scotia Power.
- $12.7 million increase in income tax receivable, reflecting
Nova Scotia Power's installments in excess of earnings, which are
lower year over year, and future income taxes in Emera Energy
Services that became a current receivable in 2005.
- $10.5 million increase in prepaid expenses, reflecting increased
posted margin paid to counterparties by Emera Energy Services.
- $23.5 million increase in long-term receivables, reflecting the
increased estimated natural gas price adjustment in NSPI, offset
partially by the reclassification of the Pengrowth receivable to
current accounts receivable.
- $67.0 million decrease in deferred charges, reflecting a refund of
the escrow deposit made in anticipation of the Bellows Falls
acquisition, which did not proceed due to lack of regulatory
approval, and normal amortization.
- $10.6 million decrease in goodwill, largely reflecting the
disposition of the company's heating oil distribution business.
- $48.5 million increase in capital assets, primarily reflecting the
acquisition of the Bear Swamp hydro-electric facility in northern
Massachusetts.
- $15.2 million increase in accounts payable and accrued charges,
reflecting higher pricing for trading activity offset by lower posted
margin in Emera Energy Services.
Significant changes in the consolidated balance sheets between
December 31, 2004 and December 31, 2003 include:
- $16.4 million decrease in inventory, primarily reflecting lower coal
inventory in NSPI.
- $10.0 million decrease in the total receivable from Pengrowth
Corporation in connection with the sale of the SOEP offshore assets
reflecting the receipt of the 2004 payment.
- $46.1 million increase in deferred assets comprised of deposits
related to Bellows Falls and Bear Swamp acquisitions, the
implementation of Section 1100 Generally Accepted Accounting
Principles, and amortization of regulatory and other deferred assets.
- $25.7 million increase in deferred credits reflecting the
implementation of the provisions of Section 1100 Generally Accepted
Accounting Principles.
Outstanding Share Data
Millions Common
Issued and Outstanding: of Share
(millions of dollars) Shares Capital
-------------------------------------------------------------------------
January 1, 2004 108.26 $1,008.4
Issued for cash under purchase plans 0.41 7.0
Options exercised under senior
management share option plan 0.20 2.8
Share-based compensation - 1.0
-------------------------------------------------------------------------
December 31, 2004 108.87 $1,019.2
Issued for cash under purchase plans 0.43 7.9
Options exercised under senior
management share option plan 0.80 13.0
Share-based compensation - 0.9
-------------------------------------------------------------------------
December 31, 2005 110.10 $1,041.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at January 31, 2006 the number of issued and outstanding common shares
was 110,171,914.
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, through operating lines of credit, an accounts receivable
securitization program and a commercial paper 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. In Q1, 2005 Emera and Nova Scotia Power established
debt shelf prospectuses in the amounts of $300 million and $400 million
respectively that provide the companies with access to long-term debt. The
prospectuses expire in April 2007. The company also has access to equity
capital markets for both common and preferred shares.
In July 2005 NSPI's Board of Directors approved an increase to the size
of its commercial paper program from $350 million to $400 million. The
company's banking syndicate provides 100% backup facility for this program.
Consolidated Cash Flow Highlights
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Net cash (used in) provided
by operating activities $(36.3) $62.9 $164.3 $304.6
Net cash (used in) provided
by financing activities (19.9) 60.7 (68.3) (57.4)
Net cash provided by (used in)
investing activities 58.5 (105.5) (117.2) (214.5)
-------------------------------------------------------------------------
Increase (decrease) in
cash and cash equivalents $2.3 $18.1 $(21.2) $32.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash used in operating activities was $36.3 million in
Q4, 2005, compared to $62.9 million of net cash provided by operating
activities in Q4, 2004. Consolidated net cash provided by operating activities
was $164.3 million in 2005 compared to $304.6 million in 2004. Highlights of
the changes are summarized in the following table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Net cash provided by operating
activities - 2004 $62.9 $304.6
Increase (decrease) in cash flow from
earnings 5.1 (19.8)
Decrease due to higher gas price
adjustment receivable in NSPI as a
result of price changes (16.8) (38.6)
Increase (decrease) due to timing of
coal and heavy fuel oil shipments
and commodity price changes in NSPI 13.8 (21.3)
Decrease due to higher prepaid expenses
primarily due to increased posted
margin Emera Energy Services has paid
to counterparties (11.0) (11.3)
Increase (decrease) due to lower
(higher) trade receivables 25.6 (35.6)
Decreased posted margin (offset by
decreased restricted cash included
in investing activities) (50.1) (23.2)
Decrease due to lower trade payables
in NSPI with the Q4 decrease due to
timing of payment to a large fuel
contractor (70.8) (6.3)
All other 5.0 15.8
-------------------------------------------------------------------------
Net cash (used in) provided by
operating activities - 2005 $(36.3) $164.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash used in financing activities was $19.9 million in
Q4, 2005, compared to $60.7 million of net cash provided by financing
activities in Q4, 2004. Net cash used in financing activities was
$68.3 million in 2005 compared to $57.4 million in 2004. Highlights of the
changes are summarized in the following table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Net cash provided by (used in)
financing activities - 2004 $60.7 $(57.4)
Higher long-term debt levels 151.5 314.5
Reduction of short-term debt (238.9) (309.3)
Accounts receivable securitization - (30.0)
Issuance of common shares 2.0 11.1
All other 4.8 2.8
-------------------------------------------------------------------------
Net cash used in financing
activities - 2005 $(19.9) $(68.3)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash provided by investing activities was $58.5 million
in Q4, 2005 compared to $105.5 million of net cash used in investing
activities in Q4, 2004. Net cash used in investing activities was
$117.2 million in 2005 compared to $214.5 million in 2004. Highlights of the
changes are summarized in the following table:
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
Net cash used in investing
activities - 2004 $(105.5) $(214.5)
Decreased restricted cash related to
posted margin 50.1 23.2
Acquisition of Bear Swamp hydro electric
facility 3.4 (49.2)
Reduced capital spending 8.2 22.3
Proceeds on disposition of Emera Fuels'
heating oil distribution business 18.3 18.4
Change in investments reflecting the 2004
deposit related to Bellows Falls and the
subsequent return of the deposit in 2005 85.8 84.3
All other (1.8) (1.7)
-------------------------------------------------------------------------
Net cash provided by (used in)
investing activities - 2005 $58.5 $(117.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contractual Obligations
(millions of dollars) Payments Due by Period
-------------------------------------------------------------------------
2007- 2009- After
Total 2006 2008 2010 2010
-------------------------------------------------------------------------
Long-term debt $1,784.7 $334.9 $124.8 $235.7 $1,089.3
Operating leases 32.7 6.3 12.4 9.8 4.2
Purchase obligations 2,800.0 918.0 826.7 584.2 471.1
Other long-term
obligations 309.2 - 0.5 - 308.7
-------------------------------------------------------------------------
Total contractual
obligations $4,926.6 $1,259.2 $964.4 $829.7 $1,873.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating lease obligations consist of the company's operating lease
agreements for office space, telecommunications services, vehicles, and
photocopiers.
Purchase obligations include the company's 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, purchasing
commitments for fuel, and physical trading commitments.
Other long-term obligations represent the company's asset retirement
obligations.
The company expects to be able to meet its obligations with cash flows
generated from operations.
Capital Resources
Capital expenditures for 2005 were approximately $129 million, including:
- $20 million related to the installation of environmental technology
(electrostatic precipitators) at NSPI's Tuft's Cove generating
station;
- $7 million related to two large transmission upgrades in BHE; and
- $6 million related to Northeast Reliability Interconnect project in
BHE.
Emera's capital budget for 2006 includes approximately $133 million for
NSPI, which is generally directed to planned and preventative maintenance
productivity-related investments, and air emissions upgrades. BHE expects to
invest approximately $70 million CAD, including approximately $55 million CAD
for several major transmission projects.
The company expects to finance its capital expenditures with funds from
operations and short-term debt. Bangor Hydro may finance a portion of the
Northeast Reliability Interconnect project with a long-term debt issue in 2006
or 2007.
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 is
currently projected at approximately $177 million. Of this amount, $16 million
is included in the 2006 NSPI capital forecast noted above. A hearing on this
matter is anticipated in the first half of 2006.
Off-Balance Sheet Arrangements
Upon privatization in 1992, NSPI became responsible for managing a
portfolio of approximately $1.1 billion of defeasance securities held in
trust. The defeasance securities must provide the principal and interest
streams to match the related defeased debt. Approximately 70%, or
$735 million, 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, 2005, the company had
sold $80.0 million (2004 - $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, 2005, the average
all-in cost of this funding was 2.97% (2004 - 2.64%). 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 (Gains) Recognized on the Balance Sheet
(millions of dollars)
-------------------------------------------------------------------------
December 31 December 31
2005 2004
-------------------------------------------------------------------------
Inventory $0.2 $1.6
Deferred charges - 0.1
Accounts payable and accrued charges - (0.3)
-------------------------------------------------------------------------
Deferred hedging losses $0.2 $1.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Fuel and purchased power increase $(3.9) $(3.7) $(20.5) $(4.9)
Interest expense increase (0.4) (1.1) (1.9) (5.0)
-------------------------------------------------------------------------
Hedging earnings impact $(4.3) $(4.8) $(22.4) $(9.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 31 December 31
2005 2004
-------------------------------------------------------------------------
Accounts receivable $8.5 $-
Energy marketing assets 20.1 10.3
Energy marketing liabilities (15.0) (9.4)
-------------------------------------------------------------------------
Mark-to-market gains $13.6 $0.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Mark-to-Market Gains (Losses) Recognized in Earnings
Three months ended Year ended
(millions of dollars) December 31 December 31
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Other revenue $(0.5) $0.8 $4.6 $0.9
Fuel and purchased power 8.5 (3.3) 8.5 -
Interest 0.4 - - -
-------------------------------------------------------------------------
Mark-to-market gains $8.4 $(2.5) $13.1 $0.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In determining the fair value of derivative financial instruments, the
company has relied on quoted market prices as at the reporting date.
Transactions With Related Parties
In the ordinary course of business, Emera purchased natural gas
transportation capacity totaling $9.5 million (2004 - $10.1 million) during
the three months ended December 31, 2005, and $39.7 million (2004 -
$45.4 million) during the year ended December 31, 2005, from the Maritimes &
Northeast Pipeline, an investment under significant influence of the company.
The amount is recognized in fuel for generation and purchased power or netted
against energy marketing margin in other revenue, and is measured at the
exchange amount. At December 31, 2005 the amount payable to the related party
is $3.0 million (December 31, 2004 - $3.2 million), is non-interest bearing
and is under normal credit terms.
Disclosure Controls and Procedures
Under the supervision and participation of our management, including the
President and Chief Executive Officer and the Chief Financial Officer, we
evaluated the effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Multilateral Instrument 52-109,
Certification of Disclosure in Issuers' Annual and Interim Filings) as of
December 31, 2005.
Based on that evaluation, the President and Chief Executive Officer and
the Chief Financial Officer concluded that our disclosure controls and
procedures are effective in making known to them material information relating
to us and our consolidated subsidiaries required to be disclosed in our
reports filed or submitted under the Multilateral Instrument.
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 pension
and other employee benefits, unbilled revenue, natural gas price adjustment
receivable, asset retirement obligations, useful lives for depreciable assets,
and 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 actual experience for 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 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. If both the expected rate of return on plan
assets and the discount rate were increased by 0.5%, the impact on the 2006
benefit cost and accrued benefit asset and liability recorded in the year end
consolidated financial statements would be as follows:
(millions of dollars) 2006
-------------------------------------------------------------------------
NSPI BHE
-------------------------------------------------------------------------
Impact of increasing the rate of return
assumption by 0.5%:
Benefit cost $(2.9) $(0.2)
Accrued benefit asset $2.9 -
Accrued benefit liability - $(0.2)
Impact of increasing the discount rate
assumption by 0.5%:
Benefit cost $(6.4) $(0.5)
Accrued benefit asset $6.4 -
Accrued benefit liability - $(0.5)
-------------------------------------------------------------------------
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 6.0% for 2005 and 2004 and BHE's rate was 6.0% for 2005, reduced from
6.25% in 2004. The expected rate to be used for 2006 is 5.25% for NSPI and
5.75% for BHE.
The expected return on plan assets is based on management's best estimate
of future returns, considering economic and consensus forecasts. The 2004 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 2006 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 estimate 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, 2005, unbilled revenues amount to
$71.8 million on a base of annual electric revenues of approximately
$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 long-term receivables.
Asset Retirement Obligations
The company recognizes assets 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, 2005, the asset retirement obligations recorded on the
balance sheet were $71.7 million (2004 - $68.5 million). The company estimates
the undiscounted amount of cash flow required to settle the obligations is
approximately $309.2 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.
Subsequently, in its rate decision for 2005, the UARB deferred the scheduled
phase-in for 2005. NSPI's 2006 rate application includes the phase-in of
Year 2 rates as per the settlement agreement.
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
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.
Change in Accounting Policies
In 2005, the company adopted the new accounting guidelines related to
variable interest entities and disclosures by entities subject to rate
regulation.
Variable Interest Entities
The Canadian Institute of Chartered Accountants ("CICA") issued
Accounting Guideline 15 Consolidation of Variable Interest Entities, which
applies to annual and interim periods beginning on or after November 1, 2004.
A variable interest entity ("VIE") is any type of legal structure in which
control is determined through contractual or other financial arrangements as
opposed to traditional voting rights, if certain conditions exist. The
guideline requires the enterprise which absorbs the majority of a VIE's
expected losses or receives the majority of a VIE's expected residual returns,
the primary beneficiary, to consolidate the VIE.
The company has variable interests in VIEs that are not consolidated
because the company is not considered the primary beneficiary. These variable
interests consist of purchase power agreements for renewable energy with
independent power producers. The company's only obligation under these
agreements is to purchase all of the energy produced, which currently is
expected to approximate 100 GWh annually.
Disclosures by Entities Subject to Rate Regulation
The CICA issued Accounting Guideline 19 Disclosures by Entities Subject
to Rate Regulation ("AcG-19"), which is effective for fiscal years ending on
or after December 31, 2005. AcG-19 is intended to ensure that financial
statement users are better informed about the existence, nature and economic
effects of rate regulation, as well as its financial statement effects.
Emera's financial statements and supporting notes reflect the new
requirements.
Future Accounting Policy Changes
The company is currently assessing the financial impact of the CICA's
Emerging Issue Committee Abstract 159 Conditional Asset Obligations
("EIC-159"). EIC-159 is to be applied retroactively, with restatement of prior
periods, to all financial statements for interim and annual reporting periods
ending after March 31, 2006. EIC-159 was issued in response to the diverse
accounting practices developed with respect to the timing of liability
recognition when the timing and/or method of settlement are conditional on a
future event.
The company is also assessing the financial impact of CICA Handbook
sections 1530 Comprehensive Income, 3855 Financial Instruments - Recognition
and Measurement, 3861 Financial Instruments - Disclosure and Presentation, and
3865 Hedges. These new standards apply to interim and annual financial
statements beginning on or after October 1, 2006.
Dividends and Payout Ratios
Emera Inc.'s common dividend rate was $0.89 ($0.2225 per quarter) per
common share in 2005 and $0.88 ($0.22 per quarter) per common share in 2004,
representing a payout ratio of approximately 80% for 2005 (2004 - 73%). In
January 2006, 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 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 developed and put forth for regulatory approval, a portfolio
strategy for fuel procurement. The strategy consists of 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, 2005 is as follows:
- For 2006, 85%
- For 2007, 23%
- For 2008, 17%
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. As at December 31,
2005, the price for the heavy fuel oil purchases has been hedged and
contracted at approximately the following:
- For 2006, 90%
- For 2007, 26%
Natural Gas
NSPI has entered into multi-year contracts to purchase approximately
65 million cubic feet 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, 2005, amounts of natural gas volumes that have been hedged and
contracted are approximately as follows:
- For 2006, 80%
- For 2007, 54%
- For 2008, 54%
Fuel Mix
The risk due to fluctuation of the Canadian dollar against the US dollar
for the cost of fuel is measured and managed. The ability to switch fuel
provides a dynamic, operational and effective option in managing commodity
price and supply risk.
Foreign Exchange
In 2006, NSPI expects approximately 80% of its anticipated net fuel costs
to be denominated in US dollars; $US from sales of surplus natural gas will
provide a natural hedge against a portion of $US denominated fuel costs.
Forward contracts are used to manage the exposure to fluctuating $US exchange
rates. Forward contracts are in place for approximately 93% of 2006
anticipated $US net fuel costs.
Payments in $US received from the US portion of the company's investment
in the Maritimes & Northeast Pipeline will be used to repay $US debt.
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 18% of total debt in 2005. Interest
forward rate agreements and swaps are used to fix rates on part of the
floating rate debt, while interest rate caps are used to limit exposure to
movements of interest rates on floating debt. For 2006, interest on
approximately 42% of floating debt is capped at a rate of 4.10%.
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
In December 2001, the Nova Scotia government released Nova Scotia's
Energy Strategy, Seizing the Opportunity. The strategy for the electricity
industry is to carefully introduce certain aspects of competition over time.
The Electricity Act, passed by the Nova Scotia Legislature in 2004, has not
yet been proclaimed. Once proclaimed, wholesale customers may purchase
electricity from other competitive suppliers. The wholesale market in Nova
Scotia is limited to the six municipal distribution utilities, which represent
approximately 1.3% of NSPI's revenues.
In May 2005, the Nova Scotia Utility and Review Board approved Nova
Scotia Power's Open Access Transmission Tariff ("OATT"). The OATT will
facilitate competition in the wholesale market. It also ensures that Nova
Scotia meets United States and other Canadian market reciprocity requirements,
thus facilitating electricity exports.
Further material restructuring of the electricity industry in Nova Scotia
is not expected for at least the medium term. The province's geographic
location, the limits of inter-provincial transmission links, and the diversity
of our customer are key factors.
NSPI faces risk with respect to the timeliness and certainty of full
recovery of fuel and other costs. In its 2005 rate decision, the UARB
discussed a Fuel Adjustment Mechanism ("FAM") and did not rule out the
possibility of a FAM in the future. NSPI plans to work with the UARB and other
stakeholders to identify and meet the conditions necessary for future approval
of a FAM. In the interim, NSPI is addressing UARB concerns with regard to fuel
and NSPI expects to undertake general rate cases more frequently to ensure it
fully recovers fuel costs.
NSPI has applied for customer rates for 2006 to recover higher fuel
expenses. The hearing is complete and the UARB's decision is anticipated in
Q1, 2006.
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, standard 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.
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 the ongoing costs
of purchasing power at above-market prices. This ability eliminates the
commodity risk involved with fixed price contracts.
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 NSPI reached a 52 month agreement with 800 unionized
employees, which expires in late 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. For example,
hydro operations within NSPI developed strategies to identify the potential
of, and increase protection against, accidental release of oil to water. Other
areas of Emera also undertook initiatives to reduce potential environmental
risks and associated costs.
Conformance with legislative and company requirements is verified through
an environmental audit program. The 2005 program maintained an objective to
review all wholly-owned operations within a three-year cycle. Results from
2005 continued to show improved environmental performance.
The Board of Directors' Environmental, Safety and Security Committee met
several times throughout 2005 and continued to carry out its oversight role in
ensuring focus is placed on environmental protection. Environmental
performance is also regularly reviewed by the Emera executive. 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.
Atmospheric Emissions
Beginning in 2005 and continuing through the end of the decade, Air
Quality Regulations under the Nova Scotia Environment Act require reductions
of sulphur dioxide (SO2), oxides of nitrogen (NOx) and mercury emitted from
Nova Scotia Power facilities. In addition, the Canadian government is a
signatory to the Kyoto Protocol. Emera continues to work with the federal and
provincial governments to develop an implementation plan that considers the
potential costs and benefits to the company and its customers.
NSPI met its 2005 Air Quality Regulations annual emissions limits. Plans
have been developed to achieve the objectives in NSPI's Air Emissions
Strategy, which addresses the entire suite of air emissions including those
linked to greenhouse gases. In 2005, NSPI:
- invested approximately $20 million on electrostatic precipitator
upgrades to reduce particulate emissions at the Tufts Cove plant,
- filed an application with the Utilities and Review Board recommending
an investment of approximately $177 million for a wet flue gas
desulphurization unit that will reduce sulphur dioxide emissions at
Lingan, and to install low NOx burners at Lingan to reduce emissions
of oxides of nitrogen,
- signed contracts with several independent power producers (IPPs) for
renewable energy that will increase NSPI's renewable energy supply by
25% over 2002 levels. These contracts represent an addition of
approximately 100 MW of supply, almost entirely from wind, with some
biomass, and
- addressed customer feedback in the 2004 Customer Energy Forum
indicating that customers want NSPI to play a stronger role in
educating consumers on energy efficiency and conservation. As part of
its 2006 Rate Case filing, NSPI proposed to invest $5 million
annually towards new energy conservation and efficiency measures
aimed at customers. The UARB's decision on this is anticipated in Q1,
2006.
Summary of Quarterly Reports
For the quarter ended
(millions of dollars, except earnings per common share)
-------------------------------------------------------------------------
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
2005 2005 2005 2005 2004 2004 2004 2004
-------------------------------------------------------------------------
Total revenues $297.1 $273.9 $275.5 $309.7 $286.5 $260.1 $268.8 $318.8
-------------------------------------------------------------------------
Net earnings
from continuing
operations $37.7 $18.1 $19.1 $47.2 $30.7 $22.0 $29.5 $45.4
-------------------------------------------------------------------------
Net earnings
applicable to
common shares $37.7 $15.9 $19.3 $48.3 $31.4 $22.1 $29.8 $46.5
-------------------------------------------------------------------------
Earnings per
common share
- basic:
Continuing
operations $0.34 $0.16 $0.18 $0.43 $0.29 $0.20 $0.27 $0.42
Discontinued
operations - (0.02) - 0.01 0.01 - - 0.01
-------------------------------------------------------------------------
$0.34 $0.14 $0.18 $0.44 $0.30 $0.20 $0.27 $0.43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per
common share
- diluted:
Continuing
operations $0.34 $0.16 $0.18 $0.41 $0.27 $0.20 $0.27 $0.40
Discontinued
operations - (0.02) - 0.01 0.01 - - 0.01
-------------------------------------------------------------------------
$0.34 $0.14 $0.18 $0.42 $0.28 $0.20 $0.27 $0.41
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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, 2005 and 2004
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 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 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 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 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 10, 2006
"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, 2005 and 2004, 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,
2005 and 2004 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 10, 2006
"Ernst & Young LLP"
Chartered Accountants
Emera Inc.
Consolidated Statements of Earnings
Year Ended December 31
millions of dollars (except earnings per common share)
2005 2004
-------------------------------------------------------------------------
Revenue
Electric $1,125.9 $1,095.7
Other 42.1 38.5
-------------------------------------------------------------------------
1,168.0 1,134.2
-------------------------------------------------------------------------
Cost of operations
Fuel for generation and purchased power 432.0 350.0
Operating, maintenance and general 248.2 245.2
Provincial, state, and municipal taxes 48.4 46.3
Provincial tax deferral (note 14) (4.5) -
Depreciation 136.1 131.2
Regulatory amortization 19.4 26.1
Allowance for funds used during construction (4.4) (4.0)
-------------------------------------------------------------------------
875.2 794.8
-------------------------------------------------------------------------
Earnings from operations 292.8 339.4
Equity earnings (note 6) 6.5 6.2
-------------------------------------------------------------------------
Earnings before interest and income taxes 299.3 345.6
Interest (note 7) 117.4 126.8
Amortization of defeasance costs 13.2 15.1
Other income (note 8) (8.0) -
-------------------------------------------------------------------------
Earnings before income taxes 176.7 203.7
Income taxes (note 9) 53.5 62.7
Income taxes deferral (note 14) (12.2) -
-------------------------------------------------------------------------
Net earnings before non-controlling interest 135.4 141.0
Non-controlling interest (note 10) 13.3 13.4
-------------------------------------------------------------------------
Net earnings from continuing operations 122.1 127.6
(Loss) earnings from discontinued
operations, net of tax (note 17) (0.9) 2.2
-------------------------------------------------------------------------
Net earnings applicable to common shares $121.2 $129.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - basic (note 11)
Continued operations $1.12 $1.18
Discontinued operations (0.01) 0.02
-------------------------------------------------------------------------
$1.11 $1.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - diluted (note 11)
Continued operations $1.10 $1.14
Discontinued operations (0.01) 0.02
-------------------------------------------------------------------------
$1.09 $1.16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
Emera Inc.
Consolidated Statements of Retained Earnings
Year Ended December 31
millions of dollars
2005 2004
-------------------------------------------------------------------------
Retained earnings, beginning of year $399.6 $365.3
Net earnings applicable to common shares 121.2 129.8
-------------------------------------------------------------------------
520.8 495.1
Dividends 97.4 95.5
-------------------------------------------------------------------------
Retained earnings, end of year $423.4 $399.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
Emera Inc.
Consolidated Balance Sheets
As at December 31
millions of dollars
Assets
2005 2004
-------------------------------------------------------------------------
Current assets
Cash and cash equivalents $21.5 $42.7
Restricted cash 5.8 18.2
Accounts receivable (note 12) 231.8 176.1
Income tax receivable 15.1 2.4
Inventory 76.1 73.4
Prepaid expenses 15.9 5.4
Future income tax assets (note 9) 9.3 3.6
Energy marketing assets 16.0 10.3
-------------------------------------------------------------------------
391.5 332.1
-------------------------------------------------------------------------
Long-term receivables (note 13) 48.4 24.9
-------------------------------------------------------------------------
Energy marketing assets 4.1 -
-------------------------------------------------------------------------
Deferred charges (note 14) 508.3 575.3
-------------------------------------------------------------------------
Future income tax assets (note 9) 19.0 34.1
-------------------------------------------------------------------------
Goodwill (note 19) 97.1 107.7
-------------------------------------------------------------------------
Investments (note 6) 101.0 96.8
-------------------------------------------------------------------------
Property, plant & equipment (note 15) 2,786.8 2,714.6
Construction work in progress 40.0 63.7
-------------------------------------------------------------------------
2,826.8 2,778.3
-------------------------------------------------------------------------
$3,996.2 $3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Current portion of long-term debt (note 22) $152.9 $100.8
Short-term debt (note 21) 88.1 145.4
Accounts payable and accrued charges 248.6 233.4
Income tax payable 1.5 1.4
Dividends payable 3.2 3.2
Energy marketing liabilities 12.1 9.4
-------------------------------------------------------------------------
506.4 493.6
-------------------------------------------------------------------------
Energy marketing liabilities 2.9 -
-------------------------------------------------------------------------
Future income tax liabilities (note 9) 78.9 82.2
-------------------------------------------------------------------------
Asset retirement obligations (note 20) 71.7 68.5
-------------------------------------------------------------------------
Deferred credits (note 14) 77.5 80.8
-------------------------------------------------------------------------
Long-term debt (note 22) 1,631.8 1,626.5
-------------------------------------------------------------------------
Non-controlling interest (note 10) 260.8 260.8
-------------------------------------------------------------------------
Shareholders' equity
Common shares (note 23) 1,041.0 1,019.2
Foreign exchange translation adjustment (note 25) (98.2) (82.0)
Retained earnings 423.4 399.6
-------------------------------------------------------------------------
1,366.2 1,336.8
-------------------------------------------------------------------------
$3,996.2 $3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contingencies (note 27)
Commitments (note 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
2005 2004
-------------------------------------------------------------------------
Operating activities
Net earnings before non-controlling interest $135.4 $141.0
Non-cash items:
Depreciation 136.1 131.2
Deferral of provincial taxes and income taxes (16.7) -
Amortization of deferred charges 15.6 19.0
Equity earnings (6.5) (6.2)
Regulatory amortization 19.4 26.1
Allowance for funds used during construction (4.4) (4.0)
Future income taxes 3.3 (10.5)
Other non-cash operating items 17.2 26.4
Discontinued operations 1.2 2.9
Other cash operating items (23.4) (28.9)
-------------------------------------------------------------------------
277.2 297.0
Change in non-cash operating working capital (112.9) 7.6
-------------------------------------------------------------------------
Net cash provided by operating activities 164.3 304.6
-------------------------------------------------------------------------
Financing activities
Retirements of long-term debt (126.7) (165.3)
Issuance of long-term debt 275.9 -
(Reduction of) increase in short-term debt (143.7) 165.6
Issuance of common shares 20.9 9.8
Dividends on common shares (97.4) (95.5)
Dividends paid by subsidiaries
to non-controlling interest (14.1) (14.1)
Long-term financing of asset sale 15.0 10.0
Accounts receivable securitization - 30.0
Other financing activities 1.8 2.1
-------------------------------------------------------------------------
Net cash used in financing activities (68.3) (57.4)
-------------------------------------------------------------------------
Investing activities
Property, plant and equipment (129.3) (151.6)
Proceeds on disposition (note 17) 18.4 -
Investments 41.7 (42.6)
Acquisition (note 16) (55.2) (6.0)
Retirement spending net of salvage (4.7) (4.7)
Proceeds from sale of assets - 1.7
Decrease (increase) in restricted cash 11.9 (11.3)
-------------------------------------------------------------------------
Net cash used in investing activities (117.2) (214.5)
-------------------------------------------------------------------------
(Decrease) increase in cash and cash equivalents (21.2) 32.7
Cash and cash equivalents, beginning of year 42.7 10.0
-------------------------------------------------------------------------
Cash and cash equivalents, end of year $21.5 $42.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents consists of:
Cash $6.9 $24.8
Short-term investments 14.6 17.9
-------------------------------------------------------------------------
Cash and cash equivalents, end of year $21.5 $42.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental disclosure of cash paid:
Interest $120.7 $130.8
Income and capital taxes $61.6 $83.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
Emera Inc.
Notes to the Consolidated Financial Statements
December 31, 2005 and 2004
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 allowed regulated rate of return on common equity ("ROE") range is
9.3% to 9.8%, with common equity allowed to grow to 40% of the capital
structure. Rates were last set using 9.55% ROE with a common equity
component of 37.5% of total capitalization.
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, 30% related to
stranded costs recoveries, and 15% 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 FERC annually on July 1, based on prior
year's revenue requirement. The current allowed ROE for transmission
operations is 11.25%.
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 15.
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 14.
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 11 years (2004 - 14 years). Unregulated
generation assets have an estimated average service life of 41 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 are being phased in over four years
beginning in 2004. Depreciation is now computed on the straight-line
basis based on the phase-in period contained within the settlement
agreement. In the March 31, 2005 decision on NSPI's 2005 rate
application, the UARB delayed the phase-in of year two rates for one
year. 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 2005 2004
---------------------------------------------------------------------
Generation
Thermal 2.38% 2.38%
Gas turbines 2.18% 2.18%
Combustion turbines 3.33% 5.00%
Hydroelectric 1.26% 1.26%
Wind turbines 5.00% 5.00%
Transmission 2.68% 2.68%
Distribution 3.96% 3.96%
General plant 5.62% 6.21%
General plant under capital lease 9.50% -
Weighted average depreciation rate 2.93% 3.07%
---------------------------------------------------------------------
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 2005 2004
---------------------------------------------------------------------
Transmission 43 42
Distribution 36 40
Other 16 15
Weighted average service life 32 34
---------------------------------------------------------------------
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 a rate depending on the type of capital project and
only eligible operating expenditures are used in the calculation.
NSPI and BHE apply overhead costs based on direct labour costs. 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, 2005 (2004 - 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 13 years as at December 31, 2005 (2004 - 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 3.53% at December 31, 2005 (December 31, 2004 - 2.37%).
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
cost, using the first-in, first-out method, and net realizable value.
n. Debt Financing and Defeasance Costs
Financing costs pertaining to debt issues are amortized over the life
of the related debt.
Upon privatization in 1992, NSPI became responsible for managing a
portfolio of approximately $1.1 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.
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.
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, and recognizes its pro-rata share of any revenue and expenses
in the Company's statement of earnings. Emera accounts for its
investment in Bear Swamp 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, Maine Electric Power Company Inc., and Intragas
Energy 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
Variable Interest Entities
In June 2003, the Canadian Institute of Chartered Accountants issued
Accounting Guideline 15 Consolidation of Variable Interest Entities. This
guideline applies to annual and interim periods beginning on or after
November 1, 2004. A variable interest entity ("VIE") is any type of legal
structure in which control is determined through contractual or other
financial arrangements as opposed to traditional voting rights, if
certain conditions exist. The guideline requires the enterprise which
absorbs the majority of a VIE's expected losses or receives the majority
of a VIE's expected residual returns, the primary beneficiary, to
consolidate the VIE.
The Company has variable interests in VIEs that are not consolidated
because the Company is not considered the primary beneficiary. These VIEs
consist of purchase power agreements for renewable energy with
independent power producers. The Company's only obligation under these
agreements is to purchase all of the energy produced, which currently is
expected to approximate 100 GWh annually.
Disclosures by Entities Subject to Rate Regulation
In May 2005, the CICA issued Accounting Guideline 19 Disclosures by
Entities Subject to Rate Regulation. The guideline applies to fiscal
years ending on or after December 31, 2005. The guideline requires
entities subject to rate regulation to disclose general information about
the rate setting process and discuss how rate regulation has effected its
financial statements. Emera's financial statements and supporting notes
reflect the new requirements.
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 reportable segments are the same as those
described in the summary of significant accounting policies.
Reportable 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 Power Bangor Hydro
---------------------------------------
millions of dollars 2005 2004 2005 2004
-------------------------------------------------------------------------
Revenues from external customers $962.8 $933.8 $147.0 $168.6
Depreciation 119.5 116.0 14.9 14.0
Cost of operations,
including depreciation 722.1 639.1 110.5 126.1
Net inter-segment
revenues/(expenses) 193.4 153.0 (2.7) (2.0)
Equity earnings - - - -
Interest expense 97.9 100.1 12.1 13.5
Other income 8.0 - - -
Income taxes 45.5 59.2 9.4 10.2
Net earnings from
continuing operations 91.2 107.3 14.9 18.5
Net earnings applicable
to common shareholders 91.2 107.3 14.9 18.5
Assets 3,061.5 2,992.8 582.6 599.8
Goodwill - - 97.1 100.3
Goodwill included in
loss on disposition - - - -
Capital expenditures 100.4 142.5 30.5 33.8
-------------------------------------------------------------------------
Other(x) Total
---------------------------------------
millions of dollars 2005 2004 2005 2004
-------------------------------------------------------------------------
Revenues from external customers $58.2 $31.8 $1,168.0 $1,134.2
Depreciation 1.7 1.2 136.1 131.2
Cost of operations,
including depreciation 42.6 29.6 875.2 794.8
Net inter-segment
revenues/(expenses) (190.7) (151.0) - -
Equity earnings 6.5 6.2 6.5 6.2
Interest expense 7.4 13.2 117.4 126.8
Other income - - 8.0 -
Income taxes (1.4) (6.7) 53.5 62.7
Net earnings from
continuing operations 16.0 1.8 122.1 127.6
Net earnings applicable
to common shareholders 15.1 4.0 121.2 129.8
Assets 352.1 356.6 3,996.2 3,949.2
Goodwill - 7.4 97.1 107.7
Goodwill included in
loss on disposition 7.4 - 7.4 -
Capital expenditures 53.6 (18.7) 184.5 157.6
-------------------------------------------------------------------------
(x) Other consists of items related to corporate activities and other
subsidiaries.
4. EMPLOYEE FUTURE BENEFITS
millions of dollars
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 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, 2005.
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, 2005 December 31, 2006
Acquired companies pension plan December 31, 2005 December 31, 2006
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total cash amount
Total cash amount for 2005, 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 $29.9 million (2004 - $34.2 million).
Accrued pension and non-pension benefit asset (liability)
millions of dollars
2005 2004
---------------------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefits pension benefits
plans plans plans plans
-------------------------------------------------------------------------
Assumptions (weighted
average)
Accrued benefit
obligation
- December 31:
Discount rate 5.25% 5.25% 6.0% 6.0%
Rate of compensation
increase 3.0 to 5.5% 3.0 to 5.5% 3.0 to 5.5% 3.0 to 5.5%
Health care trend
- initial - 9.0% - 10.0%
- ultimate - 4.0% - 4.0%
- year ultimate
reached - 2011 - 2010
Benefit cost for year
ending December 31:
Discount rate 6.0% 6.0% 6.0% 6.0%
Expected long-term
return on plan assets 7.5% - 7.5% -
Rate of compensation
increase 3.0 to 5.5% 3.0 to 5.5% 3.0 to 5.5% 3.0 to 5.5%
Health care trend
- initial - 10.0% - 11.0%
- ultimate - 4.0% - 4.0%
- year ultimate
reached - 2011 - 2010
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accrued benefit
obligations
Balance, January 1 $640.3 $31.1 $624.0 $31.2
Employer current
service cost 9.6 1.2 10.0 1.2
Employee contributions 4.7 - 5.0 -
Interest cost 38.1 1.8 36.8 1.9
Past service amendments - - (7.3) -
Actuarial losses (gains) 114.3 3.2 1.3 (1.4)
Benefits paid (30.2) (2.5) (29.5) (1.8)
Other 0.7 - - -
-------------------------------------------------------------------------
Balance, December 31 $777.5 $34.8 $640.3 $31.1
-------------------------------------------------------------------------
Fair value of plan assets
Balance, January 1 $516.0 $- $471.3 $-
Employer contributions 26.7 2.5 31.6 1.8
Employee contributions 4.7 - 5.0 -
Actual investment income 64.0 - 37.6 -
Benefits paid (30.2) (2.5) (29.5) (1.8)
-------------------------------------------------------------------------
Balance, December 31 $581.2 $- $516.0 $-
-------------------------------------------------------------------------
Reconciliation of
financial status to
accrued benefit asset,
December 31
Fair value of
plan assets $581.2 $- $516.0 $-
Accrued benefit
obligations 777.5 34.8 640.3 31.1
-------------------------------------------------------------------------
Plan deficit (196.3) (34.8) (124.3) (31.1)
Unamortized past
service gains (0.6) - (0.6) -
Unamortized actuarial
losses (gains) 273.5 (1.6) 191.3 (5.2)
Unamortized
transitional obligation 0.1 15.7 0.2 17.9
-------------------------------------------------------------------------
Accrued benefit
asset (liability) $76.7 $(20.7) $66.6 $(18.4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The expected return on plan assets is determined based on the
market-related value of plan assets of $550.9 million at January 1, 2005
(January 1, 2004 - $519.8 million), adjusted for interest on certain
cash flows during the year.
Defined benefit plans asset allocation
(% of plan assets) 2005 2004
------------------------------------------------
Acquired Acquired
Employee companies Employee companies
pension pension pension pension
plan plan plan plan
------------------------------------------------
Equity securities 66% 60% 67% 56%
Debt securities 33% 37% 31% 41%
Cash 1% 3% 2% 3%
-------------------------------------------------------------------------
Total 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2005, 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, 2005, all post-retirement benefit plans have accrued
benefit obligations in excess of assets.
Benefits expense
millions of dollars 2005 2004
-------------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefits pension benefits
plans plans plans plans
Defined benefit plan -------------------------------------------
Costs arising from
events during the year:
Current service costs $9.6 $1.2 $10.0 $1.2
Interest on accrued benefits 38.1 1.8 36.8 1.9
Less: actual return
on plan assets (64.0) - (37.6) -
Actuarial losses (gains) on
accrued benefit obligation 114.3 3.2 1.3 (1.4)
Past service gains - - (7.3) -
Other 0.7 - - -
-------------------------------------------------------------------------
Future benefit costs
before adjustments 98.7 6.2 3.2 1.7
Adjustments to recognize
long-term nature of costs:
Difference between expected
return on assets and
actual return 23.0 - (1.1) -
Amortization of
transitional obligation - 2.2 - 2.2
Difference between
amortization of actuarial
losses (gains) and actual
actuarial losses (gains) on
accrued benefit obligations (105.1) (3.6) 6.5 1.1
Difference between amortization
of past service costs and past
service costs for the year - - 7.6 -
-------------------------------------------------------------------------
Total defined benefits expense $16.6 $4.8 $16.2 $5.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Defined contribution plan
Employer expense $0.7 $- $0.8 $-
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 the following impact in
2005:
millions of dollars Increase Decrease
-------------------------------------------------------------------------
Current service cost and interest cost $0.2 $(0.1)
Accrued benefit obligation, December 31 $1.9 $(1.6)
-------------------------------------------------------------------------
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.
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, 2005.
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, 2004 December 31, 2005
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total cash amount
Total cash amount for 2005, 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 $5.3 million (2004 - $6.5 million).
Accrued pension and non-pension benefit liability
millions of dollars
2005 2004
-------------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefits pension benefits
plans plans plans plans
-------------------------------------------------------------------------
Assumptions (weighted average)
Accrued benefit obligation
- December 31:
Discount rate 5.75% 5.75% 6.00% 6.00%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
Health care trend
- initial - 9.20% - 12.00%
- ultimate - 5.00% - 5.00%
- year ultimate reached - 2011 - 2010
Benefit cost for year
ending December 31:
Discount rate 6.00% 6.00% 6.25% 6.25%
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 - 10.80% - 12.00%
- ultimate - 5.00% - 5.00%
- year ultimate reached - 2010 - 2010
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accrued benefit obligations
Balance, January 1 $86.8 $33.9 $93.2 $37.9
Employer current service cost 1.6 0.8 1.6 0.7
Interest cost 5.0 2.2 5.3 2.3
Past service amendments - (5.0) - -
Actuarial losses (gains) 0.1 7.3 (2.3) (2.2)
Benefits paid (4.6) (2.5) (4.9) (2.3)
Foreign currency
translation adjustment (3.1) (1.1) (6.1) (2.5)
-------------------------------------------------------------------------
Balance, December 31 $85.8 $35.6 $86.8 $33.9
-------------------------------------------------------------------------
Fair value of plan assets
Balance, January 1 $51.0 $1.1 $51.8 $1.2
Employer contributions 2.7 2.4 4.0 2.2
Retiree medical contributions - 0.1 - -
Actual investment income 3.1 - 3.9 -
Benefits paid (4.6) (2.5) (4.9) (2.3)
Foreign currency
translation adjustment (1.6) (0.1) (3.8) -
-------------------------------------------------------------------------
Balance, December 31 $50.6 $1.0 $51.0 $1.1
-------------------------------------------------------------------------
Reconciliation of financial
status to accrued benefit
asset, December 31
Fair value of plan assets $50.6 $1.0 $51.0 $1.1
Accrued benefit obligations 85.8 35.6 86.8 33.9
-------------------------------------------------------------------------
Plan deficit (35.2) (34.6) (35.8) (32.8)
Unamortized past service
costs (gains) 2.1 (4.8) 2.6 -
Unamortized actuarial losses 24.0 9.7 24.7 3.6
Unamortized
transitional obligation - 4.1 - 4.8
-------------------------------------------------------------------------
Accrued benefit liability $(9.1) $(25.6) $(8.5) $(24.4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the defined benefit pension plan, the expected return on plan assets
is determined based on the market-related value of plan assets of
$52.8 million at January 1, 2005 (January 1, 2004 - $55.4 million),
adjusted for interest on certain cash flows during the year.
Defined benefit plans asset allocation
(% of plan assets) 2005 2004
-------------------------------------------------
Employee pension plan Employee pension plan
-------------------------------------------------------------------------
Equity securities 62% 60%
Debt securities 37% 39%
Other 1% 1%
-------------------------------------------------------------------------
Total 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2005, 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, 2005, all post-retirement benefit plans have accrued
pension obligations in excess of assets.
Benefits expense
millions of dollars 2005 2004
------------------------------------------
Defined- Non- Defined- Non-
benefit pension benefit pension
pension benefits pension benefits
plans plans plans plans
Defined benefit plan ------------------------------------------
Costs arising from
events during the year:
Current service costs $1.6 $0.8 $1.6 $0.7
Interest on accrued benefits 5.0 2.2 5.3 2.3
Less: actual return
on plan assets (3.1) - (3.9) -
Actuarial losses (gains) on
accrued benefit obligation 0.1 7.3 (2.3) (2.2)
Past service costs - (5.0) - -
-------------------------------------------------------------------------
Future benefit costs
before adjustments 3.6 5.3 0.7 0.8
Adjustments to recognize
long-term nature of costs:
Difference between
expected return on assets
and actual return (1.2) - (0.8) -
Amortization of
transitional obligation - 0.6 - 0.7
Difference between
amortization of actuarial
losses (gains) and actual
actuarial losses (gains) on
accrued benefit obligations 0.9 (6.6) 3.1 3.0
Difference between amortization
of past service costs and past
service costs for the year 0.4 5.0 1.0 -
-------------------------------------------------------------------------
Total defined benefits expense $3.7 $4.3 $4.0 $4.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Defined contribution plan
Employer expense $0.2 - $0.4 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 the following impact in
2005:
Increase Decrease
-------------------------------------------------------------------------
Current service cost and interest cost $0.6 $(0.5)
Accrued benefit obligation, December 31 $6.9 $(5.3)
-------------------------------------------------------------------------
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 $53.0 million (2004 - $54.0 million) and the
total defined benefits expense for 2005 would be $5.8 million
(2004 - $6.0 million).
5. OPERATING LEASES
The Company has entered into operating lease agreements for office space,
telecommunication services, and certain other equipment, which expire in
2006 to 2020. Future minimum annual lease payments under the leases are
as follows:
------------------------------------------------------
millions of dollars
------------------------------------------------------
2006 $6.3
2007 6.2
2008 6.2
2009 5.4
2010 4.4
Thereafter 4.2
------------------------------------------------------
$32.7
------------------------------------------------------
------------------------------------------------------
For the year ended December 31, 2005 the Company recognized $6.2 million
(2004 - $5.2 million) in operating, maintenance and general expense.
6. INVESTMENTS AND EQUITY EARNINGS
Investments are comprised of the following:
2005 2004
------------------------------------------
Carrying Equity Carrying Equity
millions of dollars value earnings value earnings
-------------------------------------------------------------------------
Equity accounted investments
Maritimes & Northeast Pipeline $92.8 $6.5 $88.0 $6.2
Maine Yankee Atomic
Power Company 2.4 - 3.1 -
Maine Electric
Power Company Inc. 1.5 - 1.4 -
Intragas Energy 1.9 - 1.9 -
-------------------------------------------------------------------------
Total equity investments 98.6 6.5 94.4 6.2
Long-term portfolio investments 2.4 - 2.4 -
-------------------------------------------------------------------------
$101.0 $6.5 $96.8 $6.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. INTEREST
Interest expense consists of the following:
millions of dollars 2005 2004
-------------------------------------------------------------------------
Interest on long-term debt $104.8 $110.7
Interest on short-term debt 14.6 15.2
Amortization of debt financing 1.9 1.7
Foreign exchange (gains) losses (3.9) 1.6
Defeasance earnings and other interest income - (2.4)
-------------------------------------------------------------------------
$117.4 $126.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
8. OTHER INCOME
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 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 2005 2004
-------------------------------------------------------------------------
Earnings before income taxes $176.7 $203.7
-------------------------------------------------------------------------
Income taxes, at statutory rates 67.4 38.1% 77.7 38.1%
Unrecorded future income
taxes on regulated earnings (10.8) (6.1) (13.7) (6.7)
Equity earnings
not subject to tax (2.7) (1.5) (2.4) (1.2)
Large corporations tax 4.2 2.4 4.4 2.2
Other (4.6) (2.6) (3.3) (1.6)
-------------------------------------------------------------------------
53.5 30.3% 62.7 30.8%
Income taxes - current 50.2 --------- 73.2 ---------
-------------------------------------------------------------------------
Income taxes - future $3.3 $(10.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The future income tax assets and liabilities comprise the following:
Current portion Long-term portion
------------------------------------------
millions of dollars 2005 2004 2005 2004
-------------------------------------------------------------------------
Future income tax assets:
Tax loss carry forwards $7.8 $3.7 $14.6 $33.2
Financing 1.4 0.3 0.2 0.2
Property, plant and equipment - - 3.2 1.2
Other 0.1 (0.4) 1.0 (0.5)
-------------------------------------------------------------------------
$9.3 $3.6 $19.0 $34.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax liabilities:
Property, plant and equipment $80.0 $80.3
Deferred charges 16.6 21.0
Deferred credits (10.8) (10.7)
Tax loss carry forwards (2.6) (2.6)
Financing (4.2) (5.2)
Other (0.1) (0.6)
-------------------------------------------------------------------------
$78.9 $82.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2005, the company has tax losses of $64.7 million,
which are reflected in future income tax assets or netted against future
income liabilities as appropriate, and expire as follows:
-------------------------------------------------------------------------
millions of dollars
-------------------------------------------------------------------------
2006 $0.1
2007 -
2008 1.9
2009 16.7
2010 10.8
2011 -
2012 -
Thereafter 35.2
-------------------------------------------------------------------------
$64.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accounting for the impact of rate regulation:
At December 31, 2005, the unrecorded future income tax assets of NSPI are
approximately $21 million (2004 - $39 million), consisting of deductible
temporary differences of $55 million (2004 - $103 million). In the
absence of the UARB's approval of NSPI's taxes payable accounting policy,
NSPI would have had a future income tax expense of $11.0 million in 2005
(2004 - $13.5 million).
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 (2004 -
$0.8 million). The income tax recovery of $6.4 million in 2005 (2004 -
$6.4 million) is reflected as a reduction of preferred share dividends
with an offsetting increase in income tax expense.
millions of dollars 2005 2004
-------------------------------------------------------------------------
Preferred share dividend $14.1 $14.2
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 $13.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
11. EARNINGS PER SHARE
Earnings per share for 2005 are as follows:
2005
----------------------------------
Weighted
average
Net common
earnings shares EPS
($ 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 $1.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Restricted share units and deferred share units, and senior management
share options, whose exercise price exceeded the average market price for
the period, were excluded from the above calculation because they did not
dilute earnings per share.
Earnings per share for 2004 are as follows:
2004
----------------------------------
Weighted
average
Net common
earnings shares EPS
($ millions) (millions) ($)
-------------------------------------------------------------------------
Basic EPS $129.8 108.6 $1.20
Restricted Share Units and
Deferred Share Units - 0.5 (0.01)
Series C preferred shares of NSPI 5.8 6.9 (0.02)
Series D preferred shares of NSPI 7.5 7.4 (0.01)
-------------------------------------------------------------------------
Diluted EPS $143.1 123.4 $1.16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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, 2005 net accounts receivables sold amounted to
$80 million (2004 - $80 million). This agreement is in place until 2009
with the intention that it will be renewed at that time.
At December 31, 2005, the Company had unbilled revenue included in
accounts receivable in the amount of $71.8 million (2004 -
$74.6 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.
13. LONG-TERM RECEIVABLE
The current portion of the long-term receivable, which arose from Emera's
2003 sale of its 8.4% interest in the offshore platforms and sub-sea
field gathering lines of the Sable Offshore Energy Project to Pengrowth
Corporation, is $20.0 million (2004 - $15.0 million) and has been
classified in accounts receivable on the balance sheet. As at
December 31, 2005, no amount (2004 - $20 million) remains classified as
long-term. Late payments bear interest at prime plus 500 basis points.
The receivable is collateralized by the assets sold.
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 $48.4 million (2004 - $4.9 million) is
reflected in long-term receivables.
14. DEFERRED CHARGES AND CREDITS
Deferred charges and credits, including the impact of rate-regulated
accounting policies, include the following:
millions of dollars 2005 2004
-------------------------------------------------------------------------
Deferred charges:
Regulatory assets:
Pre-2003 income tax liability and related interest $146.7 $150.0
Costs to terminate/restructure
purchased power contracts 28.0 48.0
Maine Yankee decommissioning costs 19.7 24.8
Seabrook nuclear project 19.6 22.2
Deferral of income and capital taxes
not included in Q1, 2005 rates 16.7 -
Stranded cost revenue requirement levelizers 13.3 -
Deferred restructuring costs 8.7 11.0
Hydro-Quebec obligation 5.2 5.7
Other 6.9 10.9
-------------------------------------------------------------------------
264.8 272.6
-------------------------------------------------------------------------
Non-regulatory assets:
Unamortized debt financing and defeasance costs 171.2 184.0
Accrued pension and non-pension benefit asset (note 4) 56.0 48.2
Retained interest in accounts
receivable securitized (note 12) 7.6 7.5
Funds placed in escrow on
acquisition of generating stations - 48.8
345 KV line to New Brunswick - 7.8
Other 8.7 6.4
-------------------------------------------------------------------------
243.5 302.7
-------------------------------------------------------------------------
$508.3 $575.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deferred credits:
Regulatory liabilities:
Other 3.4 4.1
-------------------------------------------------------------------------
3.4 4.1
-------------------------------------------------------------------------
Non-regulatory liabilities:
Accrued pension and non-pension
benefit liability (note 4) 34.7 32.9
Maine Yankee decommissioning liability 19.7 24.8
Hydro-Quebec obligation 5.2 5.7
Unearned revenue 5.0 4.9
Other 9.5 8.4
-------------------------------------------------------------------------
74.1 76.7
-------------------------------------------------------------------------
$77.5 $80.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory assets consist of:
Pre-2003 Income Tax Liability and Related Interest
NSPI has a $146.7 million regulatory asset related to pre-2003 income
taxes that have been paid, but not yet recovered from customers. This
circumstance arose when NSPI claimed 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 decision on
NSPI's 2005 rate application, the UARB approved the amortization and
recovery of this regulatory asset over eight years, commencing in 2007.
In the absence of UARB approved recovery, the liability would have been
expensed when incurred.
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 is being recovered over an 11-year period, ending in February
2006, while the contract restructuring is being recovered over a 20-year
period ending in June 2018. The annual amortization is approximately
$19.4 million, and is reduced to $4.8 million in 2006. In the absence of
the MPUC's approval, these costs would have been expensed as incurred and
earnings would have been $19.4 million ($11.7 million after-tax) higher
in 2005 (2004 - $20.7 million or $12.4 million after-tax).
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 $5.0 million in
2005 (2004 - $5.1 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 reconcilable 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
$5.0 million ($3.0 million after-tax) higher in 2005 (2004 - $5.1 million
or $3.0 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 2005 would be
$2.1 million ($1.2 million after-tax) higher (2004 - $2.2 million or
$1.3 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. The amount of the amortization period is pending approval by the
UARB. 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.
Deferred 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 will defer $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
2005 would be $13.9 million ($8.4 million after-tax) lower
(2004 - $4.2 million or $2.5 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 2005 earnings would be $2.1 million
($2.0 million after-tax) higher (2004 - $4.0 million or $3.8 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, 2005 earnings would be $0.5 million
($0.3 million after-tax) higher (2004 - $0.7 million or $0.4 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 $4.1 million ($2.4 million
after-tax) higher in 2005 (2004 - $2.2 million or $1.3 million
after-tax).
Deferred assets include:
Funds placed in escrow on acquisition of generating stations
Brookfield Power Corporation (formerly Brascan Power Corporation) and
Emera Inc., in a 50-50 joint venture, acquired Bear Swamp, a 600 megawatt
pumped storage hydro-electric facility in northern Massachusetts, for a
total of US $92 million (Emera's share - US $46 million). As at
December 31, 2004, each party had a deposit of US $4.5 million, pending
completion of the transaction. The transaction was completed in May 2005.
A second joint venture acquisition, the 49 MW Bellow Falls hydro-electric
facility, did not receive the required regulatory approval. Emera's
escrow deposit was returned in Q4, 2005.
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 $0.9 million ($0.6 million
after-tax) lower in 2005 (2004 - $3.7 million or $2.2 million after-tax).
15. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
2005
-----------------------------------
Accumulated Net
millions of dollars Cost Depreciation Book 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 672.3 300.1 372.2
Distribution 1,284.0 571.2 712.8
Other 371.6 137.2 234.4
Other, under capital lease 0.9 - 0.9
-------------------------------------------------------------------------
$4,585.1 $1,798.3 $2,786.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2004
-----------------------------------
Accumulated Net
millions of dollars Cost Depreciation Book Value
-------------------------------------------------------------------------
Generation
Thermal $1,651.8 $604.0 $1,047.8
Gas Turbines 38.3 26.1 12.2
Combustion Turbines 76.0 3.0 73.0
Hydroelectric 364.9 118.6 246.3
Wind Turbines 2.0 0.2 1.8
Transmission 664.8 287.5 377.3
Distribution 1,254.0 535.4 718.6
Other 366.3 128.7 237.6
-------------------------------------------------------------------------
$4,418.1 $1,703.5 $2,714.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accounting for the impact of rate regulation:
At December 31, 2005, the Glace Bay generating station had a net book
value of $12.9 million (2004 - $17.8 million). During the year NSPI
amortized $6.2 million (2004 - $6.2 million) related to the plant, and
capitalized $1.3 million in AFUDC (2004 - $1.5 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.
16. 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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
17. 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) earnings from discontinued operations on the
consolidated statements of earnings:
millions of dollars 2005 2004
-------------------------------------------------------------------------
Revenue $69.7 $87.8
Earnings before income taxes $0.3 $2.7
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accounting for the impact of rate regulation:
In December 2004 Bangor Hydro sold its corporate office facilities to a
third party for cash consideration of $0.9 million. A $2.5 million loss
on the disposition was netted against accumulated depreciation in
accordance with Bangor Hydro's accounting policy approved by FERC. Absent
regulator approval, BHE earnings would have been $2.5 million
($1.5 million after-tax) lower in 2004.
18. INTEREST IN JOINT VENTURE
The following amounts represent the Company's proportionate interest in
its joint venture's financial position, operating results, and cash flows
included in the consolidated financial statements:
millions of dollars 2005
-------------------------------------------------------------------------
Current assets $3.3
Non-current assets 57.4
-------------------------------------------------------------------------
$60.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities $3.4
Non-current liabilities -
-------------------------------------------------------------------------
$3.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenues $26.6
Expenses (22.4)
-------------------------------------------------------------------------
Net earnings $4.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash provided by operations $7.0
Cash used in investing activities (62.6)
Cash provided by financing activities 57.5
-------------------------------------------------------------------------
Increase in cash $1.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
19. GOODWILL
The change in goodwill is due to the following:
millions of dollars 2005 2004
-------------------------------------------------------------------------
Balance, beginning of year $107.7 $115.1
Disposition of Emera Fuels (7.4) -
Change in foreign exchange rate (3.2) (7.4)
-------------------------------------------------------------------------
Balance, end of year $97.1 $107.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
20. ASSET RETIREMENT OBLIGATIONS
The change in asset retirement obligations is due to the following:
millions of dollars 2005 2004
-------------------------------------------------------------------------
Balance, beginning of year $68.5 $65.1
Accretion included in depreciation expense 0.9 0.8
Accretion deferred to regulatory asset 2.7 2.6
Disposition of Emera Fuels (0.2) -
Other (0.2) -
-------------------------------------------------------------------------
Balance, end of year $71.7 $68.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The key assumptions used to determine the asset retirement obligations
are as follows:
-------------------------------------------------------------------------
Estimated
undiscounted
future
obligation Expected
Credit-adjusted (millions settlement
Asset risk-free rate of dollars) date
-------------------------------------------------------------------------
Steam 5.3% $242.3 15 - 34 years
Hydro 5.3% 60.8 26 - 56 years
Combustion turbines 5.3% 5.1 2 - 18 years
Other 7.4% - 8.6% 1.0 5 - 10 years
-------------------------------------------------------------------------
$309.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Some of the Company's transmission and distribution assets may also have
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 the absence of this
deferral, net earnings for 2005 would be $2.7 million lower
(2004 - $2.6 million).
21. SHORT-TERM DEBT
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%. The operating line of credit consists of advances of $5.4 million,
which when drawn upon, bears interest at the prime rate, which on
December 31, 2005, was 5.00%. The short-term debt in NSPI and Emera is
unsecured. Bangor Hydro has borrowings outstanding under its revolving
credit loan agreement of $21.1 million that bears interest at 5.1%. This
revolving credit loan is unsecured. Emera Energy Services has a US base
rate loan for $3.5 million that bears interest at 7.25% (US prime) and is
unsecured.
For the year ended December 31, 2004, short-term debt consists of
commercial paper of $0.2 million, bankers' acceptances of $30.9 million,
and LIBOR loans of $73.9 million issues against lines of credit.
Commercial paper, bankers' acceptances and LIBOR loans bear interest at
prevailing market rates, which on December 31, 2004, averaged 2.56%,
3.13%, and 3.00%, respectively. The operating lines of credit consists of
advances of $15.1 million, which when drawn upon, bears interest at the
prime rate, which on December 31, 2004 was 4.25%. The short-term debt in
NSPI and Emera in unsecured. Also, Bangor Hydro has a revolving credit
loan agreement of $25.3 million that bears interest at 3.3%. This
revolving credit loan is secured by a First Mortgage Bond.
22. 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 2005 2004 Maturity 2005 2004
-------------------------------------------------------------------------
Emera
Medium Term Notes 6.000 6.000 2006 $100.0 $100.0
Private Placement -
secured by a letter
of credit 6.297 6.297 2006 10.0 10.0
Bankers Acceptances - 3.115 One year - 8.0
renewable
NSPI
Medium Term Notes 6.608 7.114 2006 - 2097 1,250.0 1,100.0
Debentures 9.750 9.750 2019 95.0 95.0
Commercial paper 3.020 2.557 One year 182.0 262.0
renewable
Capital lease
obligations 4.410 - 2011 0.9 -
Bangor Hydro (issued
and payable in US$)
General & Refunding
Mortgage Bonds 9.742 9.742 2020 - 2022 58.3 60.2
Financing
Authority of Maine - 7.030 2005 - 23.8
Municipal Review
Committee 5.000 5.000 2008 6.9 9.5
Senior unsecured note 6.090 6.090 2012 23.3 24.1
Senior unsecured notes 5.310 5.310 2018 58.3 60.2
Less: Sinking Funds - (25.5)
-------------------------------------------------------------------------
1,784.7 1,727.3
Less: Amount due within one year 152.9 100.8
-------------------------------------------------------------------------
$1,631.8 $1,626.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
An NSPI medium term note ("MTN") of $40.0 million bearing interest at
5.20%, maturing in 2029, is redeemable at the option of the holder in
2006. If not redeemed the interest rate on the MTN increases to 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, 2005 long-term debt and obligations under a capital
lease are due as follows:
millions of dollars
-------------------------------------------------------------------------
Year of Maturity 2005
-------------------------------------------------------------------------
One year renewable $182.0
2006 152.9
2007 3.2
2008 121.6
2009 130.4
2010 105.3
Greater than 5 years 1,089.3
-------------------------------------------------------------------------
$1,784.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
23. COMMON SHARES
AUTHORIZED:
Unlimited number of non-par value Common Shares.
ISSUED AND OUTSTANDING:
Common
Millions of Share
millions of dollars Shares Capital
-------------------------------------------------------------------------
January 1, 2004 108.26 $1,008.4
Issued for cash under purchase plans 0.41 7.0
Options exercised under senior
management share option plan 0.20 2.8
Share-based compensation - 1.0
-------------------------------------------------------------------------
December 31, 2004 108.87 1,019.2
Issued for cash under purchase plans 0.43 7.9
Options exercised under senior
management share option plan 0.80 13.0
Share-based compensation - 0.9
-------------------------------------------------------------------------
December 31, 2005 110.10 $1,041.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2005, there were 0.3 million (2004 - 1.1 million)
common shares reserved for issuance under the senior management common
share option plan, and 1.3 million (2004 - 1.4 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 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 there under. 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.
2005 2004
-------------------------------------------
Weighted Weighted
Shares average Shares average
under exercise under exercise
option price option price
-------------------------------------------------------------------------
Outstanding, beginning
of year 1,939,750 $16.76 1,480,600 $15.98
Granted 569,500 $19.46 649,800 $17.77
Exercised (797,775) $16.43 (190,650) $14.17
Expired (15,000) $17.55 - -
-------------------------------------------------------------------------
Outstanding, end of year 1,696,475 $17.81 1,939,750 $16.76
Exercisable, end of year 702,750 $17.13 689,025 $16.41
-------------------------------------------------------------------------
The weighted average contractual life of options outstanding at
December 31, 2005 is 7.6 years (2004 - 7.5 years). The range of exercise
prices for the options outstanding at December 31, 2005 is $13.70 to
$19.50 (2004 - $12.38 to $19.30).
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 runs 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
Outstanding Outstanding Outstanding
-------------------------------------------------------------------------
Balance at January 1, 2004 - 129,370 13,226
Granted 140,130 175,880 18,796
-------------------------------------------------------------------------
December 31, 2004 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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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, 2005, $3.7 million (2004 -
$5.8 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:
2005 2004
Expected dividend yield 5.20% 5.25%
Expected volatility 14.12% 14.30%
Risk-free interest rate 4.32% 4.47%
Expected life 7 years 7 years
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 options and swaps, and oil and gas
options and swaps.
Non-hedging derivative financial and commodity instruments are entered
into and are marked-to-market at each reporting date. The net margin
recognized is reflected in other revenue.
Derivative financial instruments involve credit and market risks. Credit
risks arises 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:
2005 2004
-------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
Liability Liability Liability Liability
millions of dollars (Asset) (Asset) (Asset) (Asset)
-------------------------------------------------------------------------
Long-term debt $1,784.7 $2,076.0 $1,727.3 $1,970.0
Short-term debt 88.1 88.1 145.4 145.4
Derivative financial
instruments (hedges)
Interest rate swaps 0.1 0.2 1.1 2.8
Interest rate caps
and collars (0.3) (0.3) (0.1) 0.9
Natural gas swaps (4.0) (13.4) - 1.1
Oil swaps (3.5) (16.1) - (0.1)
Foreign exchange contracts - 33.9 - 28.2
Derivative financial
instruments (non-hedges)
Energy marketing assets (20.1) (20.1) (10.3) (10.3)
Energy marketing liabilities 15.0 15.0 9.4 9.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
$150 million short-term debt over 2006 to a fixed interest rate of 4.10%
were outstanding at December 31, 2005.
Commodity Prices
The Company purchased natural gas swap contracts in 2005 to limit
exposure to fluctuations in natural gas prices. As at December 31, 2005,
the Company had hedged approximately 80% of all natural gas purchases and
sales for 2006.
The Company enters into oil swap contracts to limit exposure to
fluctuations in world prices of heavy fuel oil. As at December 31, 2005,
the Company has hedged approximately 90% of 2006 requirements and 23% of
2007 requirements.
The Company has non-hedging derivative financial instruments whose value
is marked-to-market at each reporting date. On December 31, 2005 the
Company held 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 $534.5 million
over 2006 to 2009 at a weighted average rate of CAD $1.2188 were
outstanding at December 31, 2005. There were also option contracts to
hedge US $9.3 million in 2006 at an average rate of CAD $1.2164 in 2006
outstanding at December 31, 2005.
The Company has non-hedging financial instruments whose value is
marked-to-market at each reporting date. On December 31, 2005, the
Company held 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 outside of the sphere of
electric customers, counterparty creditworthiness is assessed through
reports of credit rating agencies or other available financial
information.
25. FOREIGN EXCHANGE TRANSLATION ADJUSTMENT
(millions of dollars) 2005 2004
-------------------------------------------------------------------------
Balance, beginning of year $(82.0) $(61.1)
Effect of exchange rate changes (16.2) (20.9)
-------------------------------------------------------------------------
Balance, end of year $(98.2) $(82.0)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
26. RELATED PARTY TRANSACTIONS
During the year, in the ordinary course of business, the Company
purchased transportation capacity totaling $39.7 million (2004 -
$45.4 million) from the Maritimes and Northeast Pipeline, an investment
under significant influence of the Company. The amount is recognized in
fuel for generation or netted against energy marketing margin in other
revenue, and is measured at the exchange amount. At December 31, 2005 the
amount payable to the related party is $3.0 million (2004 - $3.2 million)
and is non-interest bearing and is under normal credit terms.
27. CONTINGENCIES
The Company may, from time to time, be involved in legal proceedings,
claims and litigation that arise in the ordinary course of business which
the Company believes would not reasonably be expected to have a material
adverse effect on the financial condition of the Company.
As part of an ongoing litigation against a coal supplier, Nova Scotia
Power was required to post an $11.5 million bond. The bond may be called
if NSPI does not prosecute the claim without delay, or if the claim is
not successful. It is not determinable whether NSPI will be successful
with its claim, and accordingly, an estimate of the potential contingent
loss cannot be made.
28. COMMITMENTS
Emera had the following significant commitments at December 31, 2005:
- The Company has a commitment to a third party, beginning in early
2004 for seven years, to outsource management of the Company's
computer infrastructure at an annual cost ranging from $8.6 million
to $10.4 million.
- NSPI has an annual requirement to purchase approximately 282 GWh of
electricity from independent power producers over varying contract
lengths ranging from nine to twenty years.
- NSPI is required to purchase approximately 61.6 million cubic feet of
natural gas per day for the next five years (subject to offshore gas
production), and an additional 4 million cubic feet per day, at the
option of the supplier, for five years.
- NSPI has commitments to purchase approximately 65,000 mmbtu per day
of transportation capacity on the Maritimes and Northeast Pipeline, a
related party, for the next five years, with 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
$1.1 billion of defeasance securities held in trust. The defeasance
securities must provide the principal and interest streams of the
related defeased debt. Approximately 70%, or $735 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
to the Lingan and Point Aconi generation stations for ten years
beginning in late 2002 at an approximate cost of $15 million per
year.
- NSPI has a commitment to purchase approximately 30,000 mmbtu's per
day of US transportation on the US side of the Maritimes and
Northeast Pipeline. The cost of this commitment over the five year
term of the contract is approximately $12.8 million annually.
- NSPI has a commitment to third parties for 2006 to 2009, to purchase
2.42 million metric tons ("mts") of import coal, 1.598 million mts of
petroleum coke, 360,000 mts of domestic coal and 4.4 million mts of
marine freight.
- NSPI has a commitment to a third party beginning in 2005 for 10 years
to operate the Point Tupper Marine Terminal at an annual cost of
$3.4 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 2006 to 2017 from independent power producers. These
commitments are reduced to approximately $2.3 million from 2018 to
2023.
- Bangor Hydro has entered into operating lease agreements for office
space (expiring in 2020) and certain transportation and other
equipment (expiring in 2006 through 2012) at an annual cost ranging
from $0.2 million to $0.7 million.
- Emera Energy Services has entered into physical trading commitments
for 2006 and 2007, the fair value of which is reflected in energy
marketing assets and liabilities on the balance sheet. The future
sales commitments are $419.8 million for 2006 and $78.9 million for
2007 and the future purchase commitments are $403.8 million for 2006
and $96.4 million for 2007.
29. GUARANTEES
Emera had the following guarantees at December 31, 2005:
- The Company has letters of credit issued against its operating
facility totaling $25.2 million (2004 - $27.2 million). Emera's
outstanding letters of credit are to secure a private placement
borrowing that matures in 2006 and to secure payments to various
vendors that expire in 2006. Nova Scotia Power's letters of credit
extend to 2006 or are renewed annually and secure payments to various
vendors. Bangor Hydro's letter of credit is to secure obligations
under an unfunded pension plan and is renewed annually.
30. COMPARATIVE INFORMATION
Certain of the comparative figures have been reclassified to conform to
the financial statement presentation adopted for 2005.
OPERATING STATISTICS
FIVE-YEAR SUMMARY
Year Ended December 31 2005 2004 2003 2002 2001
-------------------------------------------------------------------------
Electric energy
sales (GWh)
Residential 4,602.7 4,632.4 4,391.1 4,401.6 3,901.7
Commercial 3,614.1 3,567.4 3,586.1 3,401.8 2,862.3
Industrial 4,600.3 4,556.1 4,449.8 4,225.9 3,952.5
Other 716.7 819.1 1,375.4 1,641.8 654.1
-------------------------------------------------------------------------
Total electric
energy sales 13,533.8 13,575.0 13,802.4 13,671.1 11,370.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sources of energy (GWh)
Thermal - coal 9,116.3 9,490.2 9,218.7 8,861.6 8,854.8
- oil 1,581.3 1,699.3 1,537.2 289.2 690.8
- natural gas 194.3 97.0 119.5 1,578.7 1,129.1
Hydro 1,060.6 983.5 1,176.8 1,108.7 692.2
Wind 1.8 2.4 2.6 0.3 -
Purchases 2,576.6 2,339.9 2,724.5 2,765.9 776.6
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Total generation
and purchases 14,530.9 14,612.3 14,779.3 14,604.4 12,143.5
Losses and internal use 997.1 1,037.3 976.9 933.3 772.9
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Total electric
energy sold 13,533.8 13,575.0 13,802.4 13,671.1 11,370.6
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Electric customers
Residential 520,671 515,726 509,824 501,233 492,256
Commercial 50,321 49,353 48,846 47,914 46,974
Industrial 2,515 2,455 2,393 2,325 2,292
Other 9,094 8,684 8,341 11,663 10,932
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Total electric customers 582,601 576,218 569,404 563,135 552,454
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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 323 319 274 225 225
Hydroelectric 395 395 395 395 395
Wind turbines 1 1 1 1 -
Independent
power producers 74 66 67 66 66
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2,386 2,374 2,330 2,280 2,279
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Total number of employees 2,075 2,249 2,359 2,476 2,666
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km of transmission lines 6,100 6,100 6,100 6,100 6,100
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km of distribution lines 32,000 32,000 32,000 32,000 32,000
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FIVE YEAR SUMMARY
Years Ended December 31
(millions of dollars) 2005 2004 2003 2002 2001
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Statements of
Earnings Information
Revenue $1,168.0 $1,134.2 $1,146.8 $1,161.2 $932.2
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Cost of operations
Fuel for generation
and power purchased 432.0 350.0 363.3 453.2 341.6
Operating, maintenance
and general 248.2 245.2 258.6 276.5 187.4
Provincial, state and
municipal taxes 48.4 46.3 40.9 30.1 20.8
Provincial tax deferral (4.5) - - - -
Depreciation 136.1 131.2 126.9 127.0 107.3
Regulatory amortization 19.4 26.1 18.2 23.9 9.3
Allowance for funds used
during construction (4.4) (4.0) (5.1) (4.9) (5.5)
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875.2 794.8 802.8 905.8 660.9
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Earnings from operations 292.8 339.4 344.0 255.4 271.3
Equity earnings 6.5 6.2 8.6 7.0 9.6
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Earnings before interest
and income taxes 299.3 345.6 352.6 262.4 280.9
Interest 117.4 126.8 133.6 144.0 122.7
Amortization of
defeasance costs 13.2 15.1 16.7 19.4 19.8
Other income (8.0) - - - -
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Earnings before
income taxes 176.7 203.7 202.3 99.0 138.4
Income taxes 53.5 62.7 60.9 5.5 14.3
Income taxes deferral (12.2) - - - -
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Net earnings before
non-controlling interest 135.4 141.0 141.4 93.5 124.1
Non-controlling interest 13.3 13.4 13.2 10.6 12.2
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Net earnings from
continuing operations 122.1 127.6 128.2 82.9 111.9
(Loss) earnings from
discontinued operations (0.9) 2.2 1.0 0.7 2.3
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Net earnings applicable
to common shares 121.2 129.8 129.2 83.6 114.2
Common dividends 97.4 95.5 92.8 84.4 81.0
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Earnings retained
for use in Company $23.8 $34.3 $36.4 $(0.8) $33.2
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Cost of fuel for
generation - coal $260.9 $209.1 $211.9 $229.6 $202.9
- oil 100.2 91.1 90.4 20.6 40.3
- natural gas (35.4) (30.6) (58.4) 62.5 35.4
Power purchased 106.3 80.4 119.4 140.5 63.0
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Total cost of fuel
for generation and
power purchased $432.0 $350.0 $363.3 $453.2 $341.6
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Balance Sheets
Information
Current assets $391.5 $332.1 $305.5 $331.7 $334.4
Other assets 676.9 742.0 705.6 600.3 635.1
Investments 101.0 96.8 102.8 112.2 98.6
Property, plant
and equipment 2,826.8 2,778.3 2,777.0 2,863.7 2,891.3
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Total assets $3,996.2 $3,949.2 $3,890.9 $3,907.9 $3,959.4
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Current liabilities $506.4 $493.6 $520.2 $697.6 $938.9
Other liabilities 231.0 231.5 207.8 193.0 190.2
Long-term debt 1,631.8 1,626.5 1,589.5 1,417.8 1,381.4
Non-controlling interest 260.8 260.8 260.8 267.5 267.5
Common shares 1,041.0 1,019.2 1,008.4 1,000.2 845.4
Foreign currency
translation adjustment (98.2) (82.0) (61.1) 2.9 6.0
Retained earnings 423.4 399.6 365.3 328.9 330.0
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Total equity
and liabilities $3,996.2 $3,949.2 $3,890.9 $3,907.9 $3,959.4
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Statements of
Cash flow information
Cash provided by
operating activities $164.3 $304.6 $251.9 $272.4 $157.3
Cash used in (provided
by) financing activities $68.3 $57.4 $184.4 $157.3 $(507.2)
Cash used in
investing activities $117.2 $214.5 $85.2 $109.6 $566.2
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Financial ratios
($ per common share)
Earnings per common share $1.11 $1.20 $1.20 $0.85 $1.20
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