HALIFAX, Feb. 13 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net
earnings were $144.1 million in 2008, compared to $151.3 million in 2007.
Excluding the effect of mark-to-market accounting adjustments in Bear Swamp,
net earnings were $148.9 million in 2008, compared to $141.9 million in 2007.
Earnings per share were $1.29 or $1.33 excluding mark-to-market adjustment for
2008 and $1.36 or $1.28 excluding mark-to-market adjustment for 2007.
Consolidated net earnings for the three months ended December 31, 2008 were
$25.3 million compared to $36.6 million for the fourth quarter of 2007.
Quarterly earnings per share were $0.23 in 2008 compared to $0.33 in 2007.
"We are pleased with our 2008 results," said Chris Huskilson, President
and Chief Executive Officer of Emera Inc. "Positive trends in our portfolio of
businesses led to a successful year and an increase in our dividend. NSPI's
rate decision, including a fuel adjustment mechanism, was approved in
November, we increased our presence in the Caribbean with our investment in
the Grand Bahama Power Company in September, and Brunswick Pipeline
construction was completed in January 2009."
Nova Scotia Power Inc. (NSPI), Emera's largest subsidiary, contributed
$105.6 million to 2008 consolidated net earnings, compared to $100.2 million
in 2007. This increase related to the effect of having the April 2007 rate
increase in place for the entire year as well as lower income tax expense.
NSPI contributed $14.4 million to consolidated net earnings in Q4 2008,
compared to $25.2 million in Q4 2007. Earnings were lower quarter-over-quarter
largely due to higher fuel costs.
Bangor Hydro Electric Company (BHE), Emera's electricity transmission and
distribution utility subsidiary in Maine, contributed $23.1 million for the
year ended December 31, 2008 compared to $27.5 million in 2007. This decrease
was due mainly to the benefits received in 2007 related to the construction of
the NRI transmission line. BHE contributed $6.6 million to consolidated net
earnings in Q4 2008, compared to $6.7 million in Q4 2007.
Emera's Other operations contributed $15.4 million to consolidated net
earnings in 2008 compared to $23.6 million in 2007. Excluding the effect of
mark-to-market accounting changes on a long-term contract at the Bear Swamp
generating facility, net earnings from Other operations was $20.2 million in
2008 compared to $14.2 million in 2007.
Consolidated cash provided by operations was $237.2 million for the year
ended December 31, 2008, compared to $351.4 million in 2007. This decrease
relates primarily to the settlement of a receivable from a natural gas
supplier in 2007.
Forward Looking Information
This news release contains forward looking information. Actual future
results may differ materially. Additional financial and operational
information is filed electronically with various securities commissions in
Canada through the System for Electronic Document Analysis and Retrieval
(SEDAR).
Teleconference Call
Emera is holding a teleconference today at 4:00 pm Atlantic (3:00 pm
Toronto/Montreal/New York; 2:00 pm Winnipeg; noon Vancouver) to discuss the
Q4, 2008 financial results. Analysts and other interested parties wanting to
participate in the call should dial 1-888-575-8232 (in Toronto 416-406-6419)
at least 10 minutes prior to the start of the call. No pass code is required.
The teleconference will be recorded. If you are unable to join the
teleconference live, you can dial for playback toll-free at 1-800-408-3053 (in
Toronto 416-695-5800), access code (number sign)3280452 (available until midnight, Friday,
February 27, 2009). The teleconference will also be web cast live at
www.emera.com and available for playback for one year.
About Emera
Emera Inc. (EMA-TSX) is an energy and services company with $5.3 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 600,000 customers.
Emera also owns 19% of St. Lucia Electricity Services Limited, which serves
more than 50,000 customers on the Caribbean island of St. Lucia and 25% of
Grand Bahama Power Company which serves 19,000 customers on the Caribbean
island of Grand Bahama. In addition to its electric utility investments, Emera
owns the Brunswick Pipeline, a 145 kilometre gas pipeline in New Brunswick;
has a joint venture interest in Bear Swamp, a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts; a 12.9% interest in the
Maritimes & Northeast Pipeline; a 7.4% interest in Open Hydro and Emera Energy
Services which manages energy assets on behalf of third parties. Visit Emera
on the web at www.emera.com.
Management's Discussion & Analysis
As at February 13, 2009
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 2008 relative to 2007, and the full
year 2008 relative to 2007 and to 2006; and its financial position at December
31, 2008 relative to 2007. Certain factors that may affect future operations
are also discussed. Such comments will be affected by, and may involve, known
and unknown risks and uncertainties that may cause the actual results of the
company to be materially different from those expressed or implied. Those
risks and uncertainties include, but are not limited to, weather, commodity
prices, interest rates, foreign exchange, regulatory requirements and general
economic conditions. To enhance shareholders' understanding, certain
multi-year historical financial and statistical information is presented.
This discussion and analysis should be read in conjunction with the Emera
Inc. annual audited consolidated financial statements and supporting notes.
Emera follows Canadian Generally Accepted Accounting Principles ("GAAP").
Emera's wholly-owned subsidiary, Nova Scotia Power Inc.'s accounting policies
are subject to examination and approval by the Nova Scotia Utility and Review
Board ("UARB"). Emera's wholly-owned subsidiary, Bangor Hydro-Electric
Company's accounting policies are subject to examination and approval by the
Maine Public Utilities Commission ("MPUC") and the Federal Energy Regulatory
Commission ("FERC"). The accounting policies of Nova Scotia Power Inc. and
Bangor Hydro-Electric Company 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-Electric Company section of the MD&A, which is reported in US dollars
("USD") unless otherwise stated.
Additional information related to Emera, including the company's Annual
Information Form, can be found on SEDAR at www.sedar.com.
CONSOLIDATED FINANCIAL HIGHLIGHTS
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2008 2007 2008 2007 2006
-------------------------------------------------------------------------
Revenues $337.3 $343.9 $1,331.9 $1,339.5 $1,166.0
Consolidated net
earnings 25.3 36.6 144.1 151.3 125.8
Earnings per common
share - basic 0.23 0.33 1.29 1.36 1.14
Earnings per common
share - fully diluted 0.22 0.32 1.26 1.32 1.12
Cash dividends declared
per share 0.2525 0.2275 0.97 0.90 0.89
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
-------------------------------------------------------------------------
Operating Unit
Contributions 2008 2007 2008 2007 2006
-------------------------------------------------------------------------
Nova Scotia Power $14.4 $25.2 $105.6 $100.2 $104.3
Bangor Hydro Electric 6.6 6.7 23.1 27.5 16.8
Other 4.3 4.7 15.4 23.6 4.7
-------------------------------------------------------------------------
Consolidated net
earnings $25.3 $36.6 $144.1 $151.3 $125.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic $0.23 $0.33 $1.29 $1.36 $1.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic, absent
the Bear Swamp after-
tax mark-to-market
adjustment $0.26 $0.30 $1.33 $1.28 $1.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31
2008 2007 2006
-------------------------------------------------------------------------
Total assets $5,269.4 $4,221.1 $4,049.0
Total long-term liabilities 2,843.1 2,354.7 2,149.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
INTRODUCTION AND STRATEGIC OVERVIEW
Emera is a Canadian energy holding company headquartered in Halifax, Nova
Scotia. The company invests in electricity generation, transmission and
distribution as well as gas transmission and energy marketing.
Most of Emera's revenues are earned by its two wholly-owned regulated
electric utilities which it owns and operates in Northeastern North America.
Nova Scotia Power Inc. ("NSPI") is an electricity generation, transmission and
distribution company with $3.5 billion of assets providing service to 482,000
customers in the province of Nova Scotia, and Bangor Hydro-Electric Company
("BHE") is an electricity transmission and distribution company with $783
million of assets serving 117,000 customers in eastern Maine. Both businesses
operate as monopolies in their service territories, and together comprise
approximately 90% of Emera's consolidated revenues. 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 mean that NSPI and BHE can generally be expected
to produce stable earnings streams within regulated ranges. Nova Scotia and
Maine are mature electricity markets, with annual demand growth of
approximately 1%. Accordingly, Emera looks beyond its existing regulated
electricity business to supplement organic growth.
Emera's goal is to deliver annual consolidated earnings growth of 4% - 6%,
and build and diversify its earnings base. To accomplish this, Emera will
continue to seek growth from its existing businesses and will leverage its
core strength in the electricity business as it pursues both acquisitions and
greenfield development opportunities in regulated electricity transmission and
distribution and low risk generation. Emera's growth strategy also includes
serving the United States' market by capitalizing on opportunities in related
energy infrastructure businesses appropriate to its risk profile, where its
development, commercial and operational skills are needed.
Emera is growing its business through the following investments:
- Bear Swamp, a 50/50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts.
- Brunswick Pipeline, a 145 kilometer pipeline that delivers natural gas
from the Canaport(TM) Liquefied Natural Gas import terminal near Saint
John, New Brunswick, to markets in Canada and the northeastern United
States. The pipeline was mechanically complete, and received National
Energy Board approval for shipping gas, in January 2009. This
accommodates the needs and schedule of the customer, Repsol, and the
timing of completing the Canaport(TM) LNG terminal, expected in Q2
2009.
- A 12.9% interest in the $2 billion, 1,400 kilometer Maritimes &
Northeast Pipeline ("M&NP") that transports Nova Scotia's offshore
natural gas to markets in Maritime Canada and the northeastern United
States.
- Emera Energy Services, a physical energy business which purchases and
sells natural gas and electricity and provides related energy asset
management services.
- A 19% interest in St. Lucia Electricity Services Limited ("Lucelec"), a
vertically integrated electric utility on the Caribbean Island of
St. Lucia, which was acquired in January 2007.
- A 25% indirect interest in Grand Bahama Power Company Limited ("GBPC"),
a vertically integrated electric utility on Grand Bahama Island, which
was acquired in September 2008.
- A 7.35% interest in OpenHydro Group Limited ("OpenHydro"), an Irish
renewable energy company, which was acquired in February 2008.
Investment in Grand Bahama Power Company Limited
In September 2008, Emera indirectly purchased 25% of GBPC for $42.3
million USD ($45.3 million CAD) through its acquisition of 50% of the shares
of ICD Utilities Limited ("ICDU") of the Bahamas. ICDU owns 50% of the shares
of GBPC.
GBPC has 137 megawatts of installed oil-fired generating capacity. The
Grand Bahama Port Authority Limited regulates the utility and has granted GBPC
a licensed, regulated and exclusive franchise to produce, transmit, and
distribute electricity on the island until 2054. There is a fuel pass through
mechanism and flexible tariff adjustment policies to ensure that costs are
recovered and a reasonable return is earned.
Emera financed the acquisition with existing credit facilities. GBPC is
expected to add $2.5 million USD to $5.0 million USD to Emera's annual
consolidated net earnings.
Consolidated Net Earnings History
(millions of dollars)
2008 2007 2006 2005 2004 2003
Net earnings applicable
to common shares $144.1 $151.3 $125.8 $121.2 $129.8 $129.2
Net earnings applicable
to common shares,
absent the Bear Swamp
after-tax mark-to-
market adjustment $148.9 $141.9 $125.8 $121.2 $129.8 $129.2
Earnings per Share History
(dollars)
2008 2007 2006 2005 2004 2003
Earnings per share $1.29 $1.36 $1.14 $1.11 $1.20 $1.20
Earnings per share,
absent the Bear Swamp
after-tax mark-to-market
adjustment $1.33 $1.28 $1.14 $1.11 $1.20 $1.20
Structure of MD&A
This Management's Discussion and Analysis begins with an overview of
consolidated results; then presents information on the company's two primary
subsidiaries, NSPI and BHE. All other operations, including Bear Swamp,
Brunswick Pipeline, M&NP, Emera Energy Services, Lucelec, GBPC, OpenHydro and
corporate activities are grouped and discussed as "Other". Significant changes
in the consolidated balance sheets, outstanding share data, liquidity and
capital resources, financial and commodity instruments, transactions with
related parties, disclosure and internal controls, critical accounting
estimates, changes in accounting policies, dividend policy and payout ratios,
business risks and enterprise risk management, and selected quarterly trend
information are presented on a consolidated basis.
EMERA CONSOLIDATED
Consolidated Statements
of Earnings
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2008 2007 2008 2007 2006
-------------------------------------------------------------------------
Electric revenue $330.6 $322.0 $1,280.8 $1,269.5 $1,132.0
Other revenue 6.7 21.9 51.1 70.0 34.0
-------------------------------------------------------------------------
337.3 343.9 1,331.9 1,339.5 1,166.0
Fuel for generation and
purchased power 154.0 124.0 525.1 494.5 347.7
Operating, maintenance
and general 71.0 71.5 266.8 264.8 255.6
Provincial, state, and
municipal taxes 12.2 11.4 49.4 47.5 48.0
Depreciation 39.0 38.1 151.3 149.3 145.2
Regulatory amortization 9.5 7.8 28.5 31.4 22.8
-------------------------------------------------------------------------
51.6 91.1 310.8 352.0 346.7
Financing charges 24.8 27.9 123.2 133.2 148.1
Equity earnings 6.1 3.5 15.2 12.8 4.9
Other income - - - - 8.9
-------------------------------------------------------------------------
Earnings before income
taxes 32.9 66.7 202.8 231.6 212.4
Income taxes 7.0 30.1 58.1 80.3 86.6
-------------------------------------------------------------------------
Net earnings 25.9 36.6 144.7 151.3 125.8
Non-controlling interest 0.6 - 0.6 - -
-------------------------------------------------------------------------
Net earnings applicable
to common shares $25.3 $36.6 $144.1 $151.3 $125.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic $0.23 $0.33 $1.29 $1.36 $1.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - diluted $0.22 $0.32 $1.26 $1.32 $1.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of 2008
Emera Inc.'s consolidated earnings decreased $11.3 million to $25.3
million in Q4 2008 compared to $36.6 million for the same period in 2007.
Emera's annual consolidated earnings decreased $7.2 million to $144.1 million
in 2008 compared to $151.3 million in 2007, and were $125.8 million in 2006.
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 - 2006 $125.8
Decreased net earnings in NSPI due to
increased fuel expense, a new
regulatory amortization and decreased
other income; partially offset by
increased revenue and an income tax
refund and related interest recovery (4.1)
Increased net earnings in Bangor Hydro
due to increased revenue and
capitalized costs associated with the
NRI transmission project; partially
offset by increased income taxes and
the effect of the stronger Canadian
dollar 10.7
Increased net earnings in Other due
mainly to Bear Swamp's increased
energy and capacity sales and a
favourable price position; and M&NP's
capitalization of prior years'
expansion costs in Q1 2007 and
increased equity earnings due to
increased tolls and volume 18.9
-------------------------------------------------------------------------
Consolidated net earnings - 2007 $36.6 151.3
Q4 decreased net earnings in NSPI due to
increased fuel expense partially offset
by lower income taxes; year-to-date
increase is due to an electricity price
increase on April 1, 2007, decreased
financing charges and accelerated
income tax deductions, partially offset
by increased fuel expense (10.8) 5.4
Decreased net earnings in Bangor Hydro
due mainly to the capitalization of
costs associated with the NRI
transmission line in 2007 (0.1) (4.4)
Increased net earnings in Other due
mainly to allowance for funds used
during construction ("AFUDC") on
construction of the Brunswick Pipeline,
partially offset by increased interest
on short-term debt used to finance the
construction of the pipeline. Increased
year-to-date earnings also reflect Bear
Swamp's increased year-to-date energy
and forward reserve sales 6.7 6.0
Decreased net earnings in Other related
to the after-tax mark-to-market
adjustment on the commodity price
position in Bear Swamp as discussed in
Significant Items (7.1) (14.2)
-------------------------------------------------------------------------
Consolidated net earnings - 2008 $25.3 $144.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q4 basic earnings per share were $0.23 in 2008 compared to $0.33 in 2007;
and $1.29 for the full year 2008 compared to $1.36 in 2007 and $1.14 in
2006.
SIGNIFICANT ITEMS
Bear Swamp (2007 - 2008)
As part of its long-term energy and capacity supply agreement with the
Long Island Power Authority ("LIPA"), Bear Swamp has contracted with its
parents to provide the power necessary to produce the energy requirements of
the LIPA contract. One of the contracts between Bear Swamp and Emera's joint
venture partner is marked-to-market through earnings as it does not meet the
stringent accounting requirements of hedge accounting. As at December 31,
2008, the fair value of the net derivative asset was $4.9 million (December
31, 2007 - $10.5 million), which is subject to market volatility of power
prices, and will reverse over the life of the agreement as it is realized. The
agreement expires in 2021.
The mark-to-market adjustments relating to this position were as follows:
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Mark-to-market (loss) gain $(6.0) $5.9 $(8.1) $15.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
After-tax mark-to-market
(loss) gain $(3.6) $3.5 $(4.8) $9.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic $0.23 $0.33 $1.29 $1.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common
share - basic, absent the
after-tax mark-to-market
adjustment $0.26 $0.30 $1.33 $1.28
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income tax recovery (2007 - 2008)
During 2008, NSPI accelerated the deduction of capitalized expenses
pertaining to the 2007 tax year. As a result, in 2008 NSPI recorded an income
tax recovery of $6.5 million. NSPI will continue to use this methodology in
current and future years.
During 2007, NSPI filed amended tax returns for 2000 to 2004 related to
the deductibility of previously capitalized overhead expenses. Canada Revenue
Agency ("CRA") audited and approved the amended filings for these years. In
2008, NSPI amended its 2005 and 2006 tax returns on the same basis as was used
for the 2000 to 2004 years. The amendments have since been processed by CRA.
All material amounts relating to these prior year adjustments were recorded in
the 2007 financial statements of NSPI. This resulted in an income tax recovery
of $25.4 million in Q3 2007, of which $14.6 million was recorded as a
reduction of other assets and the remaining $10.8 million was recorded as a
reduction of income tax expense. In addition, in Q4 2007, NSPI recorded refund
interest of $8.6 million, $1.8 million of which was recorded as a reduction of
other assets and the remaining $6.8 million was recorded as a reduction of
financing charges. NSPI used this methodology in filing its 2007 return and
will continue to use this methodology when filing its 2008 and future income
tax returns.
Settlement of claim (2006)
In late 2005 a number of NSPI's petroleum coke suppliers were unable to
supply fuel due to hurricanes in the Gulf of Mexico, which seriously affected
their operations. As a result, NSPI incurred additional costs for replacement
fuel and other expenses, which were included in Q4 2005 fuel expense. NSPI
filed a claim with its insurers to recover applicable costs. In Q4 2006, NSPI
received $8.9 million ($5.5 million after-tax) in settlement of this claim.
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
53% is coal-fired; natural gas and/or oil together comprise another 29% of
capacity; and hydro and wind production provide 18%. In addition, NSPI has 85
MW of renewable energy, substantially wind energy, under contracts with
independent power producers. During 2008, NSPI signed power purchase
agreements for 246 MW of new wind energy sources with seven independent power
producers. NSPI also owns approximately 5,000 kilometers of transmission
facilities, and 26,000 kilometers of distribution facilities. The company has
a workforce of approximately 1,800 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.
NSPI is regulated under a cost of service model, with rates set to recover
prudently incurred costs of providing electricity service to customers, and
provide an appropriate return to investors. NSPI's return on equity ("ROE")
range for 2008 was 9.3% - 9.8%, on a maximum allowed common equity component
of 40% of total capitalization. Rates were set for 2009 using a 9.35% ROE,
with a common equity component of 37.5%. The ROE range for 2009 is 9.1% - 9.6%
on a maximum allowed common equity component of 45% of total capitalization.
Appointment
On December 1, 2008 NSPI announced plans that George Caines will become
Chair of the Board of Directors of NSPI, effective May 6, 2009. Mr. Caines
will take over from John McLennan, who will replace Derek Oland as Chair of
the Board of Emera Inc.
2009 Rate Decision
In May 2008 NSPI filed a rate application with the UARB requesting an
overall rate increase of 11.9% effective January 1, 2009. In September 2008,
NSPI reached a settlement agreement with stakeholders regarding that rate
application. The UARB approved that settlement agreement in November 2008
which includes an average rate increase of 9.4% for most customer segments
effective January 1, 2009. The approved settlement agreement also includes a
Fuel Adjustment Mechanism ("FAM") effective January 1, 2009 with the first
rate adjustment under the FAM occurring on January 1, 2010. The UARB will
oversee the FAM, including review of fuel costs, contracts and transactions.
With the implementation of the FAM, NSPI's ROE range will be reduced to 9.1% -
9.6% with 9.35% used to set rates.
2007 Cash Flow Highlights
During Q4 2007 NSPI had two significant cash receipts. NSPI received $87.6
million USD for the November 2004 to October 2007 price adjustment rebate on
an existing long-term natural gas purchase agreement. The final three-year
settlement will be received in November 2010 for the November 2007 to October
2010 price adjustment rebate. In addition, NSPI received $34.0 million in cash
related to the income tax recovery discussed in Significant Items.
2007 Rate Decision
In February 2007 the UARB approved an average increase in electricity
rates of 3.8% effective April 1, 2007. The rate increase was part of a
first-ever rate settlement agreement between NSPI and key stakeholders. NSPI's
ROE range was unchanged at 9.3% to 9.8%.
2006 Rate Decision
The UARB granted NSPI an average rate increase of approximately 8.7%
effective March 10, 2006. The UARB noted improvements NSPI had made in fuel
procurement, but determined that a previous finding related to 2002 and 2003
fuel procurement carried over into 2006, resulting in a $15.7 million
disallowance for 2006. The UARB noted that this would be the final
disallowance related to this issue.
Review of 2008
NSPI Net Earnings
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2008 2007 2008 2007 2006
-------------------------------------------------------------------------
Electric revenue $280.7 $283.1 $1,111.1 $1,102.0 $967.9
-------------------------------------------------------------------------
Fuel for generation and
purchased power 139.5 110.3 471.4 433.7 292.8
Operating, maintenance
and general 52.3 55.3 203.7 206.0 202.5
Provincial grants and
taxes 10.3 10.1 41.2 40.4 40.3
Depreciation 33.8 33.1 133.6 131.1 127.8
Regulatory amortization 6.4 4.5 17.7 17.2 8.6
Other revenue (3.5) (3.7) (15.5) (11.7) (9.6)
-------------------------------------------------------------------------
41.9 73.5 259.0 285.3 305.5
Financing charges 20.3 24.7 106.8 123.0 130.6
Other income - - - - (8.9)
-------------------------------------------------------------------------
Earnings before income
taxes 21.6 48.8 152.2 162.3 183.8
Income taxes 7.2 23.6 46.6 62.1 79.5
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings $14.4 $25.2 $105.6 $100.2 $104.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share $0.12 $0.23 $0.94 $0.90 $0.94
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's contribution to consolidated net earnings decreased $10.8 million
to $14.4 million in Q4 2008, compared to $25.2 million in Q4 2007. Annual
contribution to consolidated net earnings increased $5.4 million to $105.6
million in 2008 compared to $100.2 million in 2007, and was $104.3 million in
2006. 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 - 2006 $104.3
Increased electric revenue due to
electricity price increases on
March 10, 2006 and April 1, 2007,
higher industrial sales volume, and
colder weather partially offset by
lower export sales volume 134.1
Increased fuel expense (140.9)
Increased operating expenses mainly due
to increased storm related costs (3.5)
Increased regulatory amortization due
to the start of a new regulatory
amortization on April 1, 2007 (8.6)
Decreased other income (8.9)
Decreased financing charges mainly due
to income tax recovery interest 7.6
Decreased income taxes due to an income
tax recovery 10.8
Decreased income taxes due to lower
taxable income 6.6
All other (1.3)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2007 $25.2 100.2
Decreased electric revenue in Q4 due to
decreased commercial and industrial
sales volume; year-to-date increased
electric revenue due to an electricity
price increase on April 1, 2007 (2.4) 9.1
Increased fuel expense (29.2) (37.7)
Decreased financing charges due to
foreign exchange gains on USD
denominated monetary net assets
compared to foreign exchange losses in
2007; and lower interest costs 4.4 16.2
Decreased income taxes due to lower
taxable income, accelerated deductions
for capital items and a lower statutory
rate 16.4 15.5
Other - 2.3
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2008 $14.4 $105.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q4 Electric Sales Volume Q4 Electric Sales Revenues
Gigawatt hours ("GWh") millions of dollars
---------------------------------- -------------------------------------
2008 2007 2006 2008 2007 2006
---------------------------------- -------------------------------------
Residen- Residen-
tial 1,093 1,064 1,016 tial $129.1 $125.7 $115.5
Commercial 770 793 742 Commercial 76.9 78.5 72.0
Industrial 987 1,046 925 Industrial 64.2 67.5 58.5
Other 84 99 116 Other 10.5 11.4 11.9
---------------------------------- -------------------------------------
Total 2,934 3,002 2,799 Total $280.7 $283.1 $257.9
---------------------------------- -------------------------------------
---------------------------------- -------------------------------------
Year-to-Date ("YTD") Electric
Sales Volume YTD Electric Sales Revenues
GWh millions of dollars
---------------------------------- -------------------------------------
2008 2007 2006 2008 2007 2006
---------------------------------- -------------------------------------
Residen- Residen-
tial 4,179 4,145 3,927 tial $496.3 $485.6 $439.9
Commercial 3,115 3,161 3,023 Commercial 305.2 307.6 285.2
Industrial 4,144 4,191 2,874 Industrial 268.1 266.6 184.8
Other 334 365 681 Other 41.5 42.2 58.0
---------------------------------- -------------------------------------
Total 11,772 11,862 10,505 Total $1,111.1 $1,102.0 $967.9
---------------------------------- -------------------------------------
---------------------------------- -------------------------------------
Q4 Average Revenue / Megawatt hour
("MWh")
----------------------------------
2008 2007 2006
----------------------------------
Dollars per
MWh $96 $94 $92
----------------------------------
----------------------------------
YTD Average Revenue / MWh
----------------------------------
2008 2007 2006
----------------------------------
Dollars per
MWh $94 $93 $92
----------------------------------
----------------------------------
Electric sales volume is primarily driven by general economic conditions,
population and weather. Electricity pricing in Nova Scotia is regulated and
therefore only changes when new regulatory decisions are implemented. The
exceptions are annually adjusted rates, subscribed to by certain larger
industrial customers, and export sales which in recent years comprised less
than 1% of NSPI sales volume and are priced at market. Residential and
commercial electricity sales are seasonal, with Q1 and Q4 the strongest
periods, reflecting colder weather, and fewer daylight hours in the winter
season.
NSPI's residential load generally comprises individual homes, apartments
and condominiums. Commercial customers include small retail operations, large
office and commercial complexes, and the province's universities and
hospitals. Industrial customers include manufacturing facilities and other
large volume operations. Other electric consists of export sales, sales to
municipal electric utilities and revenues from street lighting.
Electric revenues decreased by $2.4 million to $280.7 million in Q4 2008
compared to $283.1 million in Q4 2007 due to decreased commercial and
industrial sales volume.
For the year ended December 31, 2008 electric revenues increased $9.1
million to $1,111.1 million compared to $1,102.0 million in 2007. Revenue
increases are substantially due to a 3.8% rate increase effective April 1,
2007.
For the year ended December 31, 2007 electric revenues increased by $134.1
million to $1,102.0 million compared to $967.9 million in 2006. Revenue
increases are substantially due to the 8.7% rate increase effective March 10,
2006 and a 3.8% rate increase effective April 1, 2007, increased sales volume
due to a large industrial customer returning to operations in late 2006, and
colder weather, partially offset by lower export sales.
The increase in average revenue per MWh in 2008 compared to 2007 reflects
the April 1, 2007 rate increase noted above.
The average revenue per MWh is higher in 2007 compared to 2006 reflecting
the two rate increases noted above, offset by a change in sales mix,
specifically the increase in lower priced industrial sales due to the return
to operations of a large industrial customer.
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 85 MW contracted with independent power
producers. NSPI meets the planning criteria for reserve capacity established
by the Maritime Control Area, and the Northeast Power Coordinating Council.
Management of capacity and 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, which
allows for annual maintenance programs to be carried out without compromising
reserve capacity requirements. NSPI's daily load is generally highest in the
early evening; its seasonal load is highest through the winter months.
Maximizing capacity utilization can have a positive effect on earnings, and
helps defer significant investment in additional generation capacity.
Maximizing capacity utilization primarily depends on:
- Ensuring generating plants are consistently available to service
demand - NSPI conducts ongoing planned maintenance programs, and has
sustained high availability over the past several years. NSPI maintains
low forced and unplanned outage rates compared to North American
averages.
- 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 also controls
over 400 MW of interruptible electric load; over 250 MW is supplied
under real time or time of day rates.
- Export sales - Increasing export sales when margins are satisfactory
allows energy from excess capacity to be sold when not required in the
province. NSPI operates a 24-hour marketing desk to optimize commercial
opportunities such as export sales.
NSPI Thermal Capacity Utilization
2008 2007 2006 2005 2004
75% 79% 71% 78% 82%
NSPI Thermal Capacity Availability
2008 2007 2006 2005 2004
88% 91% 90% 90% 92%
NSPI's thermal capacity utilization was 75% in 2008 compared to 79% in
2007. This was due to NSPI taking advantage of economic import energy as a
result of lower marginal cost for energy in the northeastern United States
during extended periods of warmer weather.
NSPI facilities continue to rank among the best in Canada on capacity
related performance indicators. The high availability and capability of low
cost thermal generating stations provide lower cost energy to customers. In
2008, coal plant availability was 88%. The decrease in availability from 2007
reflects extended maintenance periods. Sustained high availability and low
forced outage rates on low cost facilities are good indicators of sound
maintenance and investment practices.
Fuel Expense
Q4 Production Volume YTD Production Volume
GWh GWh
---------------------------------- -------------------------------------
2008 2007 2006 2008 2007 2006
---------------------------------- -------------------------------------
Coal & Coal &
petcoke 2,177 2,519 2,368 petcoke 9,009 9,561 9,128
Natural Natural
gas 249 333 128 gas 1,258 1,057 390
Oil & Oil &
diesel 218 45 174 diesel 339 515 431
Renewable 257 218 233 Renewable 1,068 911 998
Purchased Purchased
power 296 189 180 power 889 654 405
---------------------------------- -------------------------------------
Total 3,197 3,304 3,083 Total 12,563 12,698 11,352
---------------------------------- -------------------------------------
---------------------------------- -------------------------------------
Purchased power includes 44 GWh of Purchased power includes 148 GWh of
renewables in 2008 (2007 - 49 GWh; renewables in 2008 (2007 - 161 GWh;
2006 - 33 GWh). 2006 - 109 GWh).
Q4 Average Unit Fuel Costs
----------------------------------
2008 2007 2006
----------------------------------
Dollars per
MWh $44 $33 $28
----------------------------------
----------------------------------
YTD Average Unit Fuel Costs
----------------------------------
2008 2007 2006
----------------------------------
Dollars per
MWh $38 $34 $26
----------------------------------
----------------------------------
Solid fuel is NSPI's dominant fuel source, supplying approximately 72% of
the company's annual energy. Solid fuels have the lowest per unit fuel cost,
after hydro and NSPI owned wind production, which have no fuel cost component.
Oil, natural gas, and purchased power are next, depending on the relative
pricing of each. 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.
The average unit fuel costs increased in 2008 compared to 2007 mainly due
to the decreased value of the natural gas supply contract as reflected in the
long-term receivable, and change in generation mix due to lower coal
production due to an increase in coal plant maintenance. Increased coal prices
were partially offset by the economic use of natural gas and favourable hedge
positions as a result of this fuel switch.
The average unit fuel costs increased in 2007 compared to 2006 mainly due
to the use of higher marginal cost production because of increased load.
A substantial amount of NSPI's fuel supply comes from international
suppliers, and is subject to commodity price and foreign exchange risk. The
company manages exposure to commodity price risk utilizing a portfolio
strategy, combining physical fixed-price fuel contracts and financial
instruments providing fixed or maximum prices. Foreign exchange risk is
managed through forward and option contracts. Further details on the company's
fuel cost risk management strategies are included in the Business Risks and
Enterprise Risk Management section. Fuel contracts may be exposed to broader
global conditions which may include impacts on delivery reliability and price,
despite contracted terms.
For the three months ended December 31, 2008, fuel for generation and
purchased power increased $29.2 million to $139.5 million, compared to $110.3
million in Q4 2007. For the year ended December 31, 2008, fuel for generation
and purchased power increased $37.7 million to $471.4 million compared to
$433.7 million in 2007 and $292.8 million in 2006. 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 - 2006 $292.8
Increased sales volume due to the return
to operation of a large industrial
customer that had been shut-down for
most of 2006, colder weather, and
generation mix 103.6
Commodity price increases 6.6
Decreased net proceeds from the resale
of natural gas due to the economic
decision to use natural gas in the
production process 48.6
Decreased export sales volume (12.4)
All other (5.5)
-------------------------------------------------------------------------
Fuel for generation and purchased
power - 2007 $110.3 433.7
Increased commodity prices in Q4
primarily due to increased coal and
natural gas prices; year-to-date the
increase in coal prices was partially
offset by the economic use of natural
gas and favourable hedge positions as a
result of this fuel switch 16.9 18.3
Decreased sales volume (7.4) (9.9)
Decreased net proceeds from the resale
of natural gas due to the economic
decision to use natural gas in the
production process 6.6 8.8
Increased hydro production (3.0) (11.9)
Changes in generation mix due to
increased coal plant maintenance 16.1 30.7
Other - 1.7
-------------------------------------------------------------------------
Fuel for generation and purchased
power - 2008 $139.5 $471.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The valuation of the long-term receivable from a natural gas supplier
requires NSPI to utilize a combination of historical and future natural gas
prices. NSPI uses market-based forward indices when determining future prices.
Future prices can change from period to period which will cause a
corresponding change in the value of the long-term receivable.
Operating, Maintenance and General
Operating, maintenance and general expenses have remained relatively
unchanged over the three year period.
Provincial Grants and Taxes
NSPI pays annual grants to the Province of Nova Scotia in lieu of
municipal taxation other than deed transfer tax.
Depreciation
Depreciation expense increased slightly over the three year period due to
plant additions.
In its November 5, 2008 rate decision, the UARB approved a scheduled
year-three phase-in of the previously approved increased depreciation rates
commencing January 1, 2009.
Regulatory Amortization
Regulatory amortization increased $1.9 million to $6.4 million in Q4 2008
compared to $4.5 million in Q4 2007 due to additional amortization of the
pre-2003 income taxes partially offset by the completion of Glace Bay
generating station amortization in 2007.
For the year ended December 31, 2008 regulatory amortization increased
$0.5 million to $17.7 million compared to $17.2 million in 2007 for the
reasons noted above.
For the year ended December 31, 2007 regulatory amortization increased
$8.6 million to $17.2 million compared to $8.6 million in 2006 due to the
amortization of pre-2003 income taxes beginning in April 2007 partially offset
by the completion of the Glace Bay generating station amortization in 2007.
Other Revenue
Other revenue has increased over the three year period due to settlements
received and a reduction in the accounts receivable securitization program
which resulted in lower fees.
Financing Charges
Financing charges decreased $4.4 million to $20.3 million in Q4 2008
compared to $24.7 million in Q4 2007, and decreased $16.2 million to $106.8
million for the year ended December 31, 2008 compared to $123.0 million in
2007 primarily due to foreign exchange gains in 2008 partially offset by
income tax recovery interest in 2007.
Financing charges decreased $7.6 million, to $123.0 million for the year
ended December 31, 2007 compared to $130.6 million in 2006 primarily due to
the income tax recovery interest as discussed below. As discussed in
Significant Items, in Q4 2007 NSPI recorded income tax refund interest of $8.6
million, $1.8 million of which has been recorded as a reduction of other
assets. The remaining $6.8 million has been recorded as a reduction of
financing charges.
The company manages exposure to interest rate risk through a combination
of fixed and floating borrowing, and hedging. Interest rate caps are the
principal instrument used to hedge interest rate risk.
Other Income
In Q4 2006, Nova Scotia Power received an $8.9 million insurance
settlement on a petcoke supply interruption claim.
Income Taxes
In accordance with ratemaking regulations established by the UARB, NSPI
uses the taxes-payable method of accounting for income taxes.
In 2008, NSPI was subject to provincial capital tax (0.2125%), corporate
income tax (35.5%) and Part VI.1 tax relating to preferred dividends (40%).
NSPI also receives a reduction in its corporate income tax otherwise payable
related to the Part VI.1 tax deduction (42.6% of preferred dividends).
As discussed in Significant Items, during 2008 NSPI accelerated the
deduction of capitalized expenses pertaining to the 2007 tax year. As a
result, in 2008 NSPI recorded an income tax recovery of $6.5 million. In Q3
2007 NSPI recorded an income tax recovery of $25.4 million, of which $14.6
million was recorded as a reduction of other assets. The remaining $10.8
million was recorded as a reduction of income tax expense.
Outlook
Based on the 2009 rate decision and the current economic forecast for Nova
Scotia, NSPI expects to earn within its ROE range in 2009.
Debt Management
NSPI has established the following available credit facilities:
Short-term Maximum
millions of dollars Maturity amount
-------------------------------------------------------------------------
Operating credit facility 1 Year Revolving $500.0
-------------------------------------------------------------------------
In July 2008, medium term note series "O", 5.65%, $115 million matured.
In December 2008, NSPI issued a $150 million medium term note. This note
was issued under a reopening of Series "T", 5.75%, originally issued in
September 2003. This $150 million issue yields 6.238% and will mature in
October 2013. In January 2009, NSPI issued an additional $50 million medium
term note under an additional reopening of Series "T", yielding 5.455%. This
additional issue also matures in October 2013. The proceeds of both issues
were used to pay down short-term borrowings, incurred for general corporate
purposes.
There were no long-term debt issuances or maturities in 2007 and 2006.
The weighted average coupon rate on NSPI's outstanding medium-term and
debenture notes at December 31, 2008, was 6.84% (2007 - 6.86%). Approximately
39% of the debt matures over the next ten years; 57% matures between 2018 and
2037; and $50 million, or 4%, matures in 2097. The quoted market weighted
average interest rate for the same or similar issues of the same remaining
maturities was 6.12% as of December 31, 2008 (2007 - 5.34%).
NSPI has the following credit ratings:
DBRS S&P Moody's
-------------------------------------------------------------------------
Corporate N/A BBB Baa1
Senior unsecured debt A (low) BBB Baa1
Preferred stock Pfd-2 (low) P-3 (high) N/A
Commercial paper R-1 (low) A-2 (Cdn) P-2
-------------------------------------------------------------------------
In November 2008, Standard & Poor's ("S&P") Rating Services revised its
rating outlook on Nova Scotia Power to Positive from Stable. At the same time,
S&P confirmed NSPI's other ratings. The outlook revision reflects the recent
regulatory approval of a FAM.
In August 2008, Moody's Investors Service ("Moody's") confirmed the credit
ratings of Nova Scotia Power and revised the rating outlook from negative to
stable. The revision reflects Moody's view that NSPI has been successful in
improving its relationships with key stakeholders and the UARB. Moody's also
expects that NSPI's exposure to regulatory risk will be reduced and that there
is less likelihood of variability in NSPI's financial results following
implementation of the FAM in January 2009.
BANGOR HYDRO-ELECTRIC COMPANY
All amounts in the BHE section are reported in US dollars unless
otherwise stated.
Overview
BHE's core business is the transmission and distribution ("T&D") of
electricity. BHE is the second largest electric utility in Maine. 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 1,100 kilometers of transmission
facilities, and 7,000 kilometers of distribution facilities. BHE has recently
invested approximately $141 million in the Northeast Reliability Interconnect
("NRI"), an international electricity transmission line connecting New
Brunswick to Maine which went in service in Q4 2007 and currently has
approximately $100 million of additional transmission development in progress.
BHE has a workforce of approximately 260 people.
In addition to T&D assets, BHE has net "regulatory" assets (stranded
costs), which arose through the restructuring of the electricity industry in
the state in the late 1990s; and as a result of rate and accounting orders
issued by its regulator. BHE's net regulatory assets primarily include the
costs associated with the restructuring of an above-market power purchase
contract; and the unamortized portion on its loss on the sale of its
investment in the Seabrook nuclear facility. Unlike T&D operational assets,
which are generally sustained with new investment, the regulatory asset pool
diminishes over time, as elements are amortized through charges to earnings,
and recovered through rates. These regulatory assets total approximately $55.2
million at December 31, 2008, or 8% of BHE's net asset base.
Approximately 60% of BHE's electric rate represents distribution service,
20% relates to stranded cost recoveries, and 20% 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 operates under a traditional cost-of-service regulatory structure. In
December 2007, the MPUC approved an increase of approximately 2% in
distribution rates effective January 1, 2008. The allowed ROE used in setting
the new distribution rates is 10.2%, with a common equity component of 50%.
Until December 31, 2007, BHE's distribution service operated under an
Alternate Rate Plan ("ARP"), which provided for an ROE range of 5% to 17% on
distribution operations, with rates set at the midpoint of 11%. There was a
50/50 sharing mechanism between the company and customers outside of the
earnings band. The ARP also included performance standards and provided for
average annual reductions in distribution rates of approximately 2.5% for five
years, to 2007. Beginning January 1, 2008, the earnings band and associated
sharing mechanism, performance standard, and annual distribution rate
reductions are no longer applicable.
BHE's stranded cost rates provide for an allowed ROE of 10% on the related
asset base for the three-year period ending February 29, 2008. In December
2007 the MPUC issued an order approving an approximate 39% reduction in
stranded cost rates for the three-year period beginning March 1, 2008. The
allowed ROE used in setting the new stranded cost rates is 8.5%.
Transmission rates are set by the FERC annually on July 1, based on the
prior year's revenue requirement. The allowed ROE for transmission operations
ranges from 11.14% for low voltage transmission up to 12.64% for high voltage
transmission developed as a result of the regional system plan, which includes
the NRI transmission line.
Review of 2008
BHE Net Earnings
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2008 2007 2008 2007 2006
-------------------------------------------------------------------------
T&D revenues $25.9 $25.9 $97.6 $101.7 $101.8
Resale of purchased
power 5.4 3.7 20.4 14.6 15.2
Transmission pool
revenue 3.2 4.5 16.5 12.7 -
-------------------------------------------------------------------------
Total revenue 34.5 34.1 134.5 129.0 117.0
Fuel for generation and
purchased power 8.1 8.3 32.2 31.9 31.4
Operating, maintenance
and general 7.8 8.0 28.8 26.3 27.1
Property taxes 1.3 0.8 5.4 4.8 5.0
Depreciation 3.9 3.2 15.3 13.0 12.9
Regulatory amortization 2.6 3.2 10.1 13.2 12.6
Other (0.7) (0.8) (3.8) (2.1) (2.2)
-------------------------------------------------------------------------
Earnings before
financing charges and
income taxes 11.5 11.4 46.5 41.9 30.2
Financing charges 2.6 1.2 11.1 3.2 6.6
-------------------------------------------------------------------------
Earnings before income
taxes 8.9 10.2 35.4 38.7 23.6
Income taxes 3.6 3.5 13.9 13.0 8.8
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings - USD $5.3 $6.7 $21.5 $25.7 $14.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings - CAD $6.6 $6.7 $23.1 $27.5 $16.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per common share - CAD $0.07 $0.06 $0.21 $0.25 $0.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted
average foreign
exchange rate -
CAD /USD $1.23 $0.99 $1.07 $1.07 $1.13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
BHE's contribution to consolidated net earnings decreased $1.4 million to
$5.3 million in Q4 2008 compared to $6.7 million in Q4 2007. Annual
contribution to consolidated net earnings decreased $4.2 million to $21.5
million compared to $25.7 million in 2007, and was $14.8 million in 2006.
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 - 2006 $14.8
Increased transmission pool revenue
associated with the recovery of the NRI
transmission line from the New England
Power Pool ("NEPOOL") beginning in June
2007 12.7
Increased overheads and AFUDC
capitalized primarily as a result of
capital expenditures on the NRI
transmission line 4.0
Increased income taxes due to increased
earnings (4.2)
All other (1.6)
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2007 $6.7 25.7
Year-to-date increase primarily due to
increased net transmission pool revenue
and a decrease in miscellaneous
transmission charges (0.9) 5.0
Decreased overheads and AFUDC
capitalized primarily as a result of
completing the NRI transmission line in
Q4 2007 (1.7) (10.0)
Increased interest expense and
depreciation primarily related to the
NRI transmission line (0.4) (3.0)
Other 1.6 3.8
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2008 $5.3 $21.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
BHE's decreased contribution to consolidated net earnings in CAD in Q4
2008 compared to Q4 2007 was partially offset by the $1.3 million impact of
the weaker Canadian dollar. BHE's increased contribution to consolidated net
earnings in CAD in 2007 compared to 2006 was partially offset by the $1.5
million effect of the stronger Canadian dollar.
Electric Revenue
Q4 Electric Sales Volume Q4 Electric Sales Revenues
GWh millions of dollars
---------------------------------- -------------------------------------
2008 2007 2006 2008 2007 2006
---------------------------------- -------------------------------------
Residential 155 157 155 Residential $12.8 $13.0 $12.9
Commercial 145 149 141 Commercial 8.7 9.0 8.8
Industrial 90 102 93 Industrial 3.0 2.7 2.8
Other 2 3 3 Other 1.4 1.2 1.0
---------------------------------- -------------------------------------
Total 392 411 392 Total $25.9 $25.9 $25.5
---------------------------------- -------------------------------------
---------------------------------- -------------------------------------
YTD Electric Sales Volume YTD Electric Sales Revenues
GWh millions of dollars
---------------------------------- -------------------------------------
2008 2007 2006 2008 2007 2006
---------------------------------- -------------------------------------
Residential 591 594 589 Residential $47.6 $49.6 $49.1
Commercial 604 606 598 Commercial 34.5 36.5 36.1
Industrial 350 379 372 Industrial 10.0 11.1 11.3
Other 10 12 12 Other 5.5 4.5 5.3
---------------------------------- -------------------------------------
Total 1,555 1,591 1,571 Total $97.6 $101.7 $101.8
---------------------------------- -------------------------------------
---------------------------------- -------------------------------------
Q4 Average Revenue / MWh
----------------------------------
2008 2007 2006
----------------------------------
Dollars per
MWh $66 $63 $65
----------------------------------
----------------------------------
YTD Average Revenue / MWh
----------------------------------
2008 2007 2006
----------------------------------
Dollars per
MWh $63 $64 $65
----------------------------------
----------------------------------
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 were flat at $25.9 million in Q4 2008 compared to Q4
2007. For the year ended December 31, 2008, electric revenues decreased $4.1
million to $97.6 million compared to $101.7 million for 2007 due to decreased
sales volume and decreased stranded cost rates. For the year ended December
31, 2007, electric revenues were unchanged at $101.7 million compared to
$101.8 million in 2006.
The changes in average revenue per MWh in 2008 compared to 2007 reflects
the July 1, 2007 reduction in transmission rates and the March 1, 2008
reduction in stranded cost rates, offset by the January 1, 2008 increase in
distribution rates and an increase in transmission rates on July 1, 2008.
Resale of Purchased Power, and Fuel for Generation and Purchased Power
BHE has several above-market purchase power contracts pre-dating the Maine
market restructuring. Power purchased under these arrangements is resold to a
third party at market rates as determined through a bid process administered
and approved by the MPUC. The difference between the cost of the power
purchased under these arrangements and the revenue collected from the third
party is recovered through stranded cost rates.
Transmission Pool Revenue
Transmission pool revenue includes recovery of the NRI transmission line
from NEPOOL, which began in June 2007, offset by NEPOOL transmission
infrastructure investment charges. BHE recovers the cost of its regionally
funded transmission infrastructure investment through the transmission pool
revenue based on a regional formula that is updated on June 1st of each year.
Transmission pool revenue decreased by $1.3 million in Q4 2008 to $3.2
million compared to $4.5 million in Q4 2007 due to increased regional charges
from increased transmission infrastructure investment. For the year ended
December 31, 2008, transmission pool revenue increased $3.8 million to $16.5
million compared to $12.7 million for 2007. Much of the year over year
increase is due to 12 months of pool revenue in 2008 from the NRI transmission
line compared to seven months in 2007, partially offset by increased regional
charges.
Depreciation
Depreciation expense increased $0.7 million to $3.9 million in Q4 2008
compared to $3.2 million in Q4 2007; and increased $2.3 million to $15.3
million in 2008 compared to $13.0 million in 2007 primarily due to
depreciation on the NRI transmission line which went into service in Q4 2007.
Financing Charges
Financing charges increased $1.4 million to $2.6 million in Q4 2008
compared to $1.2 million in Q4 2007 and increased $7.9 million to $11.1
million for the year ended December 31, 2008, compared to $3.2 million in 2007
primarily due to increased debt used to finance the NRI transmission line and
decreased AFUDC capitalized on the NRI transmission line which went into
service in Q4 2007.
Financing charges decreased $3.4 million to $3.2 million for the year
ended December 31, 2007, compared to $6.6 million in 2006 primarily due to
increased capitalized AFUDC related to the NRI transmission line partially
offset by increased debt used to finance the NRI transmission line.
Income Taxes
BHE uses the future income tax method of accounting for income taxes.
BHE is subject to corporate income tax at the statutory rate of 40.8%
(combined federal and state income tax rate).
Outlook
BHE's net earnings for 2009 are expected to be slightly higher than 2008
primarily due to increased transmission investment recoveries.
Debt Management
BHE has established the following credit facilities:
Short-term Maximum
millions of dollars Maturity amount
-------------------------------------------------------------------------
Unsecured revolving facility 2 year revolving- $60.0
matures in June 2010
-------------------------------------------------------------------------
In September 2007, the company completed a private placement of $50
million in senior unsecured notes at an average interest rate of 5.74% of
which $30 million will mature in September 2014 and $20 million will mature in
September 2017. The primary use of these proceeds was to fund the NRI
transmission line. Proceeds were used to pay down a $40 million interim bank
credit line used as bridge financing, and short-term debt.
The weighted-average coupon rate on BHE's long-term debt outstanding at
December 31, 2008 was 6.87% (2007 - 6.82%). Approximately 70% of the debt
matures over the next 10 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 6.95% as of December 31, 2008
(2007 - 5.62%).
BHE has no public debt, and accordingly has no requirement for public
credit ratings. BHE 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.
OTHER, INCLUDING CORPORATE COSTS
All activities of Emera other than its two wholly-owned regulated electric
utilities are incorporated into Other, including:
- Bear Swamp, a 50/50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts. Bear Swamp typically
pumps water into its reservoir using lower priced off-peak power, and
uses that hydro capacity to generate electricity during higher priced
on-peak periods.
- Brunswick Pipeline, a 145 kilometer pipeline that delivers natural gas
from the Canaport(TM) Liquefied Natural Gas import terminal near
Saint John, New Brunswick, to markets in Canada and the northeastern
United States. The pipeline was mechanically complete, and received
National Energy Board approval for shipping gas, in January 2009. This
accommodates the needs and schedule of the customer, Repsol, and the
timing of completing the Canaport(TM) LNG terminal, expected in Q2
2009.
- A 12.9% interest in the $2 billion, 1,400 kilometer M&NP that
transports Nova Scotia's offshore natural gas to markets in Maritime
Canada and the northeastern United States.
- Emera Energy Services, a physical energy business which purchases and
sells natural gas and electricity and provides related energy asset
management services. Emera Energy Services operates with minimal day-
to-day commodity risk exposure. Volatility in natural gas markets
usually results in increased opportunities for Emera Energy Services.
- A 19% interest in Lucelec, a vertically integrated electric utility on
the Caribbean Island of St. Lucia, which was acquired in January 2007.
- A 25% indirect interest in GBPC, a vertically integrated utility
serving 19,000 customers on Grand Bahama Island, which was acquired in
September 2008.
- A 7.35% interest in OpenHydro, an Irish renewable tidal energy company,
which was acquired in February 2008.
- Certain corporate-wide functions such as executive management,
strategic planning, treasury services, tax planning, business
development, and corporate governance; and financing and income taxes
associated with the corporation's business outside of its two wholly-
owned regulated electric utilities.
Review of 2008
Bear Swamp, Brunswick Pipeline, and Emera Energy Services are reported on
an earnings before interest and other income taxes basis ("EBIT"), and M&NP,
Lucelec and GBPC are reported on an equity earnings basis.
Other Net Earnings
millions of dollars
(except earnings per Three months ended Year ended
common share) December 31 December 31
-------------------------------------------------------------------------
2008 2007 2008 2007 2006
-------------------------------------------------------------------------
Bear Swamp - operational $2.4 $3.6 $15.8 $8.9 $1.4
Bear Swamp - mark-to-
market (6.0) 5.9 (8.1) 15.7 -
Brunswick Pipeline 7.0 - 15.6 - -
M&NP 4.6 2.6 12.2 10.6 4.9
Emera Energy Services 1.8 1.9 7.3 12.2 15.1
Lucelec 0.3 0.9 1.8 2.2 -
GBPC 1.2 - 1.2 - -
Corporate costs & other (2.2) (4.8) (12.3) (14.4) (9.6)
-------------------------------------------------------------------------
9.1 10.1 33.5 35.2 11.8
Interest 8.6 2.4 20.8 7.4 10.0
-------------------------------------------------------------------------
0.5 7.7 12.7 27.8 1.8
Income taxes (4.4) 3.0 (3.3) 4.2 (2.9)
-------------------------------------------------------------------------
4.9 4.7 16.0 23.6 4.7
Non-controlling interest (0.6) - (0.6) - -
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings $4.3 $4.7 $15.4 $23.6 $4.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per share $0.04 $0.04 $0.14 $0.21 $0.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated net
earnings, absent the
Bear Swamp after-tax
mark-to-market
adjustment $7.9 $1.2 $20.2 $14.2 $4.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to
consolidated earnings
per share, absent the
Bear Swamp after-tax
mark-to-market
adjustment $0.07 $0.01 $0.18 $0.13 $0.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The total contribution of Other to consolidated net earnings decreased
$0.4 million to $4.3 million in Q4 2008 compared to $4.7 million in Q4 2007.
Annual contribution to consolidated net earnings decreased $8.2 million to
$15.4 million in 2008 compared to $23.6 million in 2007, and was $4.7 million
in 2006. 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 - 2006 $4.7
Increased Bear Swamp - operational due
to increased energy and capacity sales 7.5
Increased Bear Swamp - mark-to-market
due to a favourable commodity price
position 15.7
Decreased Emera Energy Services as a
result of changes in supply, market
performance, and a stronger Canadian
dollar (2.9)
Increased M&NP due to expansion costs
that were expensed throughout 2006 and
then capitalized in Q1 2007 and
increased equity earnings due to
increased tolls and volume 5.7
Equity earnings from Lucelec which was
purchased in Q1 2007 2.2
Increased corporate costs and other due
to increased business development
activity and depreciation (4.8)
Increased income taxes related to
increased earnings (7.1)
All other 2.6
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2007 $4.7 23.6
Increased year-to-date Bear Swamp -
operational due to increased energy and
forward reserve sales (1.2) 6.9
Decreased Bear Swamp - mark-to-market
due to an unfavourable commodity price
position (11.9) (23.8)
Increased Brunswick Pipeline due to
AFUDC on construction of the pipeline 7.0 15.6
Decreased Emera Energy Services
primarily due to reduced activity (0.1) (4.9)
Increased interest due to increased
short-term debt used to finance the
construction of Brunswick Pipeline and
foreign exchange losses in 2008
compared to foreign exchange gains in
2007 (6.2) (13.4)
Decreased income taxes due to decreased
earnings 7.4 7.5
Equity earnings from GBPC which was
purchased in Q3 2008 1.2 1.2
-------------------------------------------------------------------------
Other 3.4 2.7
-------------------------------------------------------------------------
Contribution to consolidated net
earnings - 2008 $4.3 $15.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bear Swamp
Bear Swamp EBIT represents Emera's investment in the Bear Swamp joint
venture.
Operational
Bear Swamp EBIT - operational decreased quarter over quarter to $2.4
million in Q4 2008 compared to $3.6 million in Q4 2007; and increased to $15.8
million in 2008 compared to $8.9 million in 2007 and $1.4 million in 2006.
During 2006 a hedging program was implemented to provide more consistent
margins and resulted in a mark-to-market loss in 2006, which reversed in 2007.
During Q1 2007, Bear Swamp finalized a long-term agreement with the Long
Island Power Authority to provide LIPA with 345 MW of capacity to May 31, 2010
(approximately 55% of Bear Swamp's total capacity); and 100 MW thereafter, to
April 30, 2021. In addition, Bear Swamp will provide LIPA with 12,200 MWh of
super-peak and peak energy weekly, (approximately 35% of the plant's available
energy) at a fixed price, with an annual increase, over the 15 year term of
the agreement. Bear Swamp has contracted with its parent companies for the
power supply necessary to produce the energy requirements of the LIPA
agreement.
Mark-to-market
As mentioned above, Bear Swamp has contracted with its parents to provide
the power necessary to produce the energy requirements of the LIPA contract.
One of the contracts between Bear Swamp and Emera's joint venture partner is
marked-to-market through earnings as it does not meet the stringent accounting
requirements of hedge accounting. As at December 31, 2008, the fair value of
the net derivative asset was $4.9 million (December 31, 2007 - $10.5 million),
which is subject to market volatility of power prices, and will reverse over
the life of the agreement as it is realized. The agreement expires in 2021.
Brunswick Pipeline
Brunswick Pipeline was mechanically complete, and received National Energy
Board approval for shipping gas, in January 2009. This accommodates the needs
of the customer, Repsol, and the timing of completing the Canaport(TM) LNG
terminal, expected in Q2 2009. Capital costs of Brunswick Pipeline are
expected to be $465 million plus additional AFUDC and operating expenses
capitalized as a result of the delay in receiving gas from the Canaport(TM)
LNG terminal. Revenue from the customer will begin when the terminal is
operational, but no later than September 2009.
M&NP Equity Earnings
Equity earnings for M&NP were $4.6 million in Q4 2008 compared to $2.6
million in Q4 2007. The increase in earnings was a result of proceeds related
to a settlement agreement between M&NP and EnCana Marketing (USA) Inc.
("EnCana"), a reduction in interest expense related to the US portion of the
pipeline, and a weaker Canadian dollar. In late 2007, M&NP and EnCana entered
into an agreement whereby M&NP would expand its facilities on the US portion
of the pipeline and M&NP would provide firm transport service to EnCana. In
2008, EnCana terminated the agreement and a settlement agreement was reached
in Q4 2008. A portion of the settlement proceeds has been recognized in Q4
2008 with the remaining portion deferred until 2009.
For the year ended December 31, 2008 M&NP equity earnings were $12.2
million compared to $10.6 million in 2007 due to the reasons noted above.
For the year ended December 31, 2007 M&NP equity earnings were $10.6
million compared to $4.9 million in 2006 primarily due to expansion costs that
were expensed throughout 2006 and then capitalized in Q1 2007. During Q2 2006,
M&NP filed an application with the FERC to expand its US pipeline system to
carry volumes from the proposed Brunswick Pipeline to markets in the
northeastern United States. Construction of the $307 million USD proposed
expansion facilities began in June 2007, in conjunction with the building of
Brunswick Pipeline. M&NP was expensing development costs associated with the
expansion until FERC approval was obtained in Q1 2007 when these costs were
capitalized as part of the US pipeline expansion. Emera's portion of the
required capital contribution for the expansion facilities was $21 million
USD.
During Q3 2008, M&NP repaid its outstanding debt related to the US portion
of the pipeline through equity contributions from the partners, which M&NP
will return to the partners once new financing is in place. The Company's
portion of the equity contribution was $46.5 million USD ($47.0 million CAD).
M&NP is expected to issue long-term debt in 2009, subject to capital market
conditions.
Income Taxes
All businesses included in Other follow the future income taxes method of
accounting for income taxes, excluding Brunswick Pipeline which uses the
taxes-payable method as allowed for ratemaking purposes. Taxes are recognized
on pre-tax income, excluding M&NP, Lucelec and GBPC equity earnings that are
recorded net of tax. Variations in income tax expense are largely affected by
earnings and foreign exchange fluctuations, along with changes in the
statutory tax rate.
Outlook
Net earnings for 2009, after adjusting for the mark-to-market effect of
the commodity price position in Bear Swamp, will increase over 2008 due to the
Brunswick Pipeline being mechanically complete and ready for gas
transportation in January 2009.
Debt Management
Emera has established the following credit facilities outside its
regulated electric utilities:
Short-term Maximum
millions of dollars Maturity amount
-------------------------------------------------------------------------
Operating and acquisition credit
facility 1 Year Revolving $600.0
Bridge credit facility June 20, 2009 $200.0
-------------------------------------------------------------------------
During Q4 2008, Emera entered into a $200 million non-revolving bridge
credit facility ("bridge facility"), maturing June 30, 2009. The amount of the
bridge facility is required to be reduced by the proceeds of any debt or
equity issuance by Emera.
During Q2 2007, Bear Swamp completed a $125 million USD financing using a
senior secured non-revolving credit facility. The five-year credit facility
bears interest at a LIBOR-based facility rate, is secured by the assets of
Bear Swamp, and is due in May 2012. Proceeds of the financing were distributed
equally to Emera and its joint venture partner.
On a consolidated basis, Emera's target percentage of debt to total
capitalization is 50%-55%. The company manages long-term debt terms such that
the average is not less than ten years.
The credit ratings issued by Dominion Bond Rating Service, Standard &
Poor's, and Moody's Investor Services are unchanged from 2007 and are as
follows:
DBRS S&P Moody's
-------------------------------------------------------------------------
Long-term corporate BBB (high) BBB Baa2
-------------------------------------------------------------------------
In November 2008, Standard & Poor's ("S&P") rating agency revised the
corporate and senior unsecured debt rating outlook of Emera to Positive from
Stable.
In August 2008, Moody's Investors Service confirmed the credit ratings of
Emera and revised the rating outlook from negative to stable. The revision
reflects Moody's view that NSPI has been successful in improving its
relationships with key stakeholders and the UARB. Moody's also expects that
NSPI's exposure to regulatory risk will be reduced and that there is less
likelihood of variability in NSPI's financial results following implementation
of the FAM.
CONSOLIDATED BALANCE SHEETS
Significant changes in the consolidated balance sheets between December
31, 2008 and December 31, 2007 include:
Increase
millions of dollars (Decrease) Explanation
-------------------------------------------------------------------------
Assets
Cash $(14.2) See consolidated cash flow highlights
section.
Accounts receivable 65.8 Lower accounts receivable securitized,
increased posted margin to
counterparties, and the effect of the
weaker Canadian dollar.
Inventory 31.5 Increased coal volumes and commodity
prices.
Derivatives in a 141.9 Favourable USD price positions partially
valid hedging offset by unfavourable commodity price
relationship positions. The effective portion of the
(including long-term change is recognized in accumulated
portion) other comprehensive income.
Long-term receivable 48.7 Increased receivable from a natural gas
supplier.
Goodwill 19.2 Weaker Canadian dollar.
Investments subject 193.1 Additional investment in MN&P, indirect
to significant investment in GBPC through the
influence investment in ICDU, and equity
earnings. The non-controlling interest
in ICDU is reflected in non-controlling
interest below.
Available-for-sale 14.4 Investment in OpenHydro.
investments
Property, plant & 547.0 Capital spending in Brunswick Pipeline,
equipment and NSPI and BHE, along with the effect of
construction work the weaker Canadian dollar.
in progress
-------------------------------------------------------------------------
Liabilities and
Shareholders' Equity
Accounts payable 24.4 Timing of payments.
Derivatives in a 92.6 Unfavourable commodity price positions
valid hedging partially offset by favourable USD
relationship price positions. The effective portion
(including long-term of the change is recognized in
portion) accumulated other comprehensive income.
Held-for-trading 23.0 Unfavourable commodity price positions.
derivatives The portion related to NSPI's
(including long-term regulatory liabilities is recognized in
portion) other assets.
Future income tax 25.4 Increased timing differences relating to
liabilities depreciable assets.
Other liabilities 25.9 Increased NSPI regulatory liability
related to held-for-trading contracts,
and the effect of the weaker Canadian
dollar.
Short-term debt and 622.7 Increased short-term debt to finance
long-term debt Brunswick Pipeline, increased posted
(including current margin and the effect of the weaker
portion) Canadian dollar.
Non-controlling 39.0 Investment in ICDU.
interest
Common shares 15.2 Shares issued under purchase plans and
stock options exercised.
Accumulated other 139.8 Primarily represents the favourable
comprehensive income effect of the Canadian dollar on the
company's investment in Bangor Hydro,
and changes in USD and commodity price
hedge positions.
Retained earnings 31.0 Net earnings in excess of dividends
paid.
-------------------------------------------------------------------------
OUTSTANDING SHARE DATA
Common Share
Capital
Millions of millions of
Issued and Outstanding: Shares dollars
-------------------------------------------------------------------------
December 31, 2006 110.93 $1,055.2
Issued for cash under purchase plans 0.45 9.0
Options exercised under senior management
share option plan 0.09 1.7
Share-based compensation - 0.3
-------------------------------------------------------------------------
December 31, 2007 111.47 $1,066.2
Issued for cash under purchase plans 0.39 8.0
Options exercised under senior management
share option plan 0.35 6.4
Share-based compensation - 0.8
-------------------------------------------------------------------------
December 31, 2008 112.21 $1,081.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at January 30, 2009 the number of issued and outstanding common shares
was 112.25 million.
LIQUIDITY AND CAPITAL RESOURCES
The company generates cash primarily through its operations in regulated
utilities involving the generation, transmission and distribution of
electricity. NSPI's and BHE's customer bases are diversified by both sales
volume and revenues among residential, commercial, industrial and other.
Circumstances that could affect the company's ability to generate cash include
fuel commodity price changes, general economic downturns in Nova Scotia and
Maine, the loss of one or more large customers, and regulatory decisions
affecting customer rates. The UARB approved a FAM that reduces NSPI's exposure
to fuel price volatility effective January 1, 2009, providing a mechanism for
NSPI to recover these fuel costs beginning in 2010.
In addition to internally generated funds, Emera Inc. and NSPI have in
aggregate access to $1.1 billion committed syndicated revolving bank lines of
credit, of which $375 million is undrawn and available as at December 31,
2008. Emera Inc. has access to $600 million of this facility and NSPI has
access to $500 million. NSPI has an active commercial paper program for up to
$400 million, of which outstanding amounts are 100% backed by the bank lines
referred to above and this results in an equal amount of that credit being
considered drawn.
Emera's and NSPI's revolving bank lines have a maturity date in June 2009
which can be extended annually for an additional 364 days with the approval of
the syndicated banks. At each maturity date Emera and NSPI have the option to
convert all amounts drawn on the bank credit line to a one year non-revolving
term credit.
In October 2008, the company negotiated an additional $200 million in a
committed non-revolving bank line of credit as a bridge facility for Brunswick
Pipeline. As at December 31, 2008, $66 million is undrawn and available. This
non-revolving bank line matures in June 2009. The company intends to finance
Brunswick Pipeline with a longer term debt facility in 2009.
BHE has a $60 million USD revolving bank line of which $12 million USD was
undrawn and available as at December 31, 2008. This facility matures in June
2010.
NSPI expects to have access to capital markets to enable it to refinance
the $125 million Series C preferred shares and the $125 million long-term note
maturing in June, while maintaining sufficient levels of operating liquidity
in 2009.
In December 2008, NSPI completed a $150 million medium-term note issue,
proceeds of which were used to pay down outstanding commercial paper debt. In
January 2009, NSPI completed a $50 million medium-term note issue, which was
also used to pay down outstanding short-term debt; these proceeds increased
the $375 million in available credit referenced previously to $425 million. As
at December 31, 2008, Emera and Nova Scotia Power had debt shelf prospectuses
in the amounts of $400 million and $250 million respectively. Subsequent to
the January 2009 $50 million medium-term note issue, the Nova Scotia Power
debt shelf prospectus is now $200 million.
As at December 31, 2008 Credit Line Undrawn and
millions of dollars Committed Utilized Available
-------------------------------------------------------------------------
Nova Scotia Power $500 $171 $329
Emera 600 554 46
Emera bridge facility 200 134 66
Bangor Hydro - in USD 60 48 12
-------------------------------------------------------------------------
NSPI issues commercial paper, 100% backed by a syndicated bank line of
credit, to finance short-term cash requirements and has accessed the market as
required despite liquidity and pricing pressures arising as a result of the
disruption to capital markets. On a few occasions market demand for NSPI's
commercial paper was less than required and the company accessed its bank
credit line.
NSPI has an accounts receivable securitization program as described in the
Off-Balance Sheet Arrangements section. NSPI temporarily suspended its
accounts receivable securitization program in January 2008 due to a lack of
investor interest. The program expires in May 2009 and NSPI's ability to sell
its receivables is subject to acceptance by the sponsor bank to buy the
receivables. The company does not expect to use this facility in 2009. The
company refinanced this $25 million debt through its commercial paper program.
North American financial markets experienced significant volatility
beginning in 2007 and continuing throughout 2008 due to concerns related to
the state of both the global debt market and economy. In the past, the company
has been able to access capital markets. Given the current state of North
American financial markets, we expect that access to capital markets will
continue to be available to the company although possibly at a higher cost.
NSPI and BHE are each capable of paying dividends to Emera provided they do
not breach their debt to capitalization ratios after giving effect to the
dividend payment.
The pressure on global debt markets may affect the credit worthiness of
certain counterparties of Emera and its subsidiaries. Emera continues to
perform regular credit risk assessments on its counterparties and deposits are
required on any high risk accounts. Further information on Emera's credit risk
can be found in the Business Risks and Enterprise Risk Management section.
Pension Funding
Emera has defined pension plans which, similar to most North American
pension plans, had negative asset returns during 2008. Consistent with
Canadian GAAP and Emera's accounting policy, the company amortizes the net
actuarial gain or loss, which exceeds 10% of the greater of the accrued
benefit obligation ("ABO") and the market-related value of assets, over active
plan members' average remaining service period, which is currently 10 years.
Any required amortization of 2008 investment losses in 2009 will be offset by
Emera's use of smoothed asset values rather than market values for accounting
purposes; and amortization of gains due to a lower ABO measured at December
31, 2008 as a result of a higher discount rate at year end. Emera's selection
of the discount rate is in accordance with Canadian GAAP. The net result is
that the 2009 pension cost is expected to be lower than 2008 pension cost.
The 2008 asset loss will increase Emera's cash contribution to the pension
plan. The increased cash requirements in 2009 will be approximately $14
million higher than 2008. This is projected to increase by another $15 million
- $20 million in 2010. All pension plan contributions are tax deductible and
will be funded with cash from operations.
Emera's pension plan is managed with a diversified portfolio of asset
classes, investment managers and geographic investments. Emera does not expect
to make any changes to the management of its plan as a result of the market
performance in 2008.
Consolidated Cash Flow Highlights
Significant changes in the consolidated cash flow statements between
December 31, 2008 and December 31, 2007 include:
Three months ended
December 31
millions of dollars 2008 2007 Explanation
-------------------------------------------------------------------------
Cash and cash $28.5 $8.6
equivalents,
beginning of period
Provided by (used
in):
Operating activities (17.1) 207.8 In 2008, increased non-cash
working capital partially offset
by cash earnings.
In 2007, cash earnings and
decreased non-cash working
capital due to settlement of a
receivable from a natural gas
supplier in NSPI.
Investing activities (146.7) (83.3) In 2008, capital spending,
including Brunswick Pipeline,
and an additional investment in
M&NP.
In 2007, capital spending,
including NRI project and
Brunswick Pipeline projects.
Financing activities 147.5 (106.7) In 2008, increased debt levels,
partially offset by dividends on
common shares.
In 2007, reduced debt levels and
dividends on common shares.
-------------------------------------------------------------------------
Cash and cash $12.2 $26.4
equivalents, end of
year
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year ended
December 31
millions of dollars 2008 2007 Explanation
-------------------------------------------------------------------------
Cash and cash $26.4 $19.5
equivalents,
beginning of period
Provided by (used
in):
Operating activities 237.2 351.4 In 2008, cash earnings partially
offset by increased non-cash
working capital.
In 2007, cash earnings partially
offset by increased non-cash
working capital.
Investing activities (671.6) (288.9) In 2008, capital spending in
Brunswick Pipeline, NSPI, and
BHE, and acquisition of a 7.35%
interest in OpenHydro and a 50%
interest in ICDU.
In 2007, capital spending,
including the NRI transmission
line and Brunswick Pipeline
projects, and acquisition of a
19% interest in Lucelec.
Financing activities 420.2 (55.6) In 2008, increased debt levels,
partially offset by dividends on
common shares and decreased
accounts receivable securitized.
In 2007, dividends on common
shares and decreased accounts
receivable securitized,
partially offset by increased
debt levels.
-------------------------------------------------------------------------
Cash and cash $12.2 $26.4
equivalents, end of
year
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contractual Obligations
The consolidated contractual obligations over the next five years and
thereafter include:
millions of dollars Payments Due by Period
Total 2009 2010 2011
-------------------------------------------------------------------------
Long-term debt $2,304.6 $774.7 $106.3 $6.0
Preferred shares issued by
subsidiary 260.0 125.0 - -
Operating leases 24.5 10.0 10.0 1.5
Purchase obligations 2,419.1 317.8 243.9 207.5
Other long-term
obligations 321.0 2.1 1.5 2.2
-------------------------------------------------------------------------
Total contractual
obligations $5,329.2 $1,229.6 $361.7 $217.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
millions of dollars Payments Due by Period
2012 2013 After 2013
-------------------------------------------------------------------------
Long-term debt $106.8 $255.5 $1,055.3
Preferred shares issued by
subsidiary - - 135.0
Operating leases 0.4 0.4 2.2
Purchase obligations 154.1 106.3 1,389.5
Other long-term
obligations 2.1 41.9 271.2
-------------------------------------------------------------------------
Total contractual
obligations $263.4 $404.1 $2,853.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating lease obligations: Emera's operating lease obligations consist
of operating lease agreements for office space, telecommunications services,
and photocopiers.
Purchase obligations: Emera has purchasing commitments for electricity
from independent power producers, transportation of coal, outsourced
management of the company's computer infrastructure, natural gas,
transportation capacity on the Maritimes & Northeast Pipeline, fuel, and
construction costs on the Brunswick Pipeline.
Other long-term obligations: The company has asset retirement and other
long-term obligations.
The company expects to be able to meet its obligations with cash flows
generated from operations.
Capital Resources
Capital expenditures, including AFUDC, were approximately $590 million for
2008 and included:
- $167 million in Nova Scotia Power;
- $44 million in Bangor Hydro; and
- $375 million in Brunswick Pipeline.
Outlook
Emera's capital budget for 2009 includes approximately $220 million for
NSPI, which is generally directed toward customer growth and system
reliability, planned and preventative maintenance, productivity-related
investments, air emissions upgrades and a new corporate office. BHE expects to
invest approximately $54 million USD, including approximately $32 million USD
for major transmission projects. Brunswick Pipeline expects to invest
approximately $60 million plus additional AFUDC and operating expenses
capitalized.
The company expects to finance its capital expenditures with funds from
operations and debt.
Off-Balance Sheet Arrangements
Upon privatization of the former provincially owned Nova Scotia Power
Corporation ("NSPC") in 1992, NSPI became responsible for managing a portfolio
of defeasance securities, which as at December 31, 2008 totaled $1.1 billion,
held in trust for Nova Scotia Power Finance Corporation ("NSPFC"), an
affiliate of the Province of Nova Scotia. NSPI is responsible to ensure that
the defeasance securities provide the principal and interest streams to match
the related defeased NSPC debt. Approximately 73% 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 has a
market value 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 at the
sole discretion of the Trust on a revolving non-recourse basis. As of December
31, 2008, there were no accounts receivable sold to the Trust (2007 - $25.0
million). The agreement is in place until May 2009 and NSPI's ability to sell
its receivables is subject to acceptance by the sponsor bank to buy the
receivables. Securitization has provided NSPI with an alternative source of
short-term funding. The securitization program was temporarily suspended in
January 2008 due to a lack of investor interest. For the year ended December
31, 2007, the average all-in cost of this funding was 4.91%. In the event of
termination of this arrangement, NSPI would utilize another credit 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 financial instruments consisting mainly of
foreign exchange forward contracts, interest rate options and swaps, and coal,
oil and gas options and swaps. In addition, the company has contracts for the
physical purchase and sale of natural gas, and physical and financial
contracts held-for-trading ("HFT"). Collectively these contracts are referred
to as derivatives.
The company recognizes the fair value of all its derivatives on its
balance sheet, except for non-financial derivatives that qualify and are
designated as contracts held for normal purchase or sale.
Derivatives 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, for cash flow hedges,
the effective portion of the change in the fair value of derivatives is
deferred to other comprehensive income and recognized in earnings in the same
period the related hedged item is realized. Any ineffective portion of the
change in the fair value of derivatives is recognized in net earnings in the
reporting period. The total ineffectiveness recognized by the company was a
$0.8 million gain in Q4 2008 and a $0.2 million gain for the year ended
December 31, 2008.
Where the documentation or effectiveness requirements of hedge accounting
are not met, the change in the fair value of the derivatives is recognized in
earnings in the reporting period. The company also recognizes the change in
the fair value of its HFT derivatives in earnings of the reporting period. The
company has not designated any financial instruments to be included in the HFT
category.
Nova Scotia Power has contracts for the purchase and sale of natural gas
at its Tufts Cove generating station ("TUC") that are considered HFT
derivatives and accordingly are recognized on the balance sheet at fair value.
This reflects NSPI's history of buying and reselling any natural gas not used
in the production of electricity at TUC. Changes in fair value of HFT
derivatives are normally recognized in net earnings.
