$15.3 Million Tax Expense Deferred As NSPI Awaited New Rates
HALIFAX, Nova Scotia, May 3 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated
net earnings were $48.3 million in Q1, 2005, compared to $46.5 million in Q1,
2004. Quarterly earnings per share were $0.44, compared to $0.43 in 2004. The
Q1, 2005 earnings include a $15.3 million ($0.14 per share) deferral of income
and other tax expenses. The deferral, pursuant to a regulatory agreement,
mitigated the Q1 financial impact of implementing new electricity rates for
Nova Scotia Power (NSPI) on April 1, 2005 rather than at the beginning of the
year. NSPI had filed a rate application in May 2004 for new rates for 2005.
The company's regulator rendered its decision on March 31, 2005. The amount of
the deferral, and the amortization period are subject to regulatory approval.
"For Emera, 2005 will be a challenging year," said Chris Huskilson,
Emera's President and Chief Executive Officer. "Nova Scotia Power's fuel costs
will be higher than the amount provided for in its recent rate decision, and
as a result we expect that NSPI will earn below its allowed rate of return. We
are in the process of reviewing our position for 2006. We remain focused on
developing profitable opportunities for investment and diversification in the
northeast."
NSPI's contribution to consolidated net earnings was $40.8 million in Q1,
2005, including the deferral of the $15.3 million tax expense referred to
above. This compares to $38.8 million in Q1, 2004. Earnings before taxes (EBT)
were $16.3 million lower quarter over quarter, primarily reflecting a
$22.5 million increase in fuel expense due to reduced gas sales margin and
higher coal prices. In addition to the tax deferral, the lower EBT reduced
taxes by a further $7.9 million quarter over quarter.
Bangor Hydro, Emera's electricity transmission and distribution utility
in Maine, contributed $4.1 million to consolidated net earnings in Q1, 2005
compared to $5.8 million for the same period in 2004, primarily reflecting
small decreases in residential and commercial sales year over year.
Other operations contributed $3.4 million to consolidated net earnings in
Q1 2005, compared to $1.9 million in Q1, 2004. Included in the 2004 amount
were business development expenses of $1.9 million pertaining to the write-off
of an investment in Greyhawk gas storage.
Consolidated cash provided by operating activities was $18.0 million in
Q1, 2005, compared to $55.7 million in Q1, 2004, primarily due to NSPI's
increased fuel costs.
Recent Corporate Developments
On March 31, 2005, the Nova Scotia Utility and Review Board (UARB)
rendered its decision on Nova Scotia Power's 2005 rate application. The UARB
granted NSPI an average rate increase of approximately 5.3%, effective
April 1, 2005. Other key features of the decision include:
- full recovery of $150 million Section 21 income tax deposit over eight
years, commencing in 2007,
- an allowed Return on Equity of 9.55%, (formerly 10.15%)
- an allowed Common Equity Component of 37.5%, (formerly 35%)
- 10.4% increase effective January 1, 2005 for industrial customers with
annually adjusted rates
The primary difference between NSPI's proposed rate settlement and the
regulatory decision is an $18 million reduction in the allowed fuel expense.
The UARB also did not accept NSPI's proposal to defer $13 million of 2005 fuel
costs. The company has revised its financial outlook to incorporate the impact
of the decision. Net earnings for 2005 are expected to be approximately
$22-$27 million lower than 2004, reflecting the disallowance of fuel costs
referred to above, and the effect of the lower allowed return on equity.
About Emera Inc.
Emera Inc. (EMA-TSX) is an energy and services company with 570,000
customers and $4.0 billion in assets. The core business of Emera is
electricity and the company has two wholly-owned regulated electric utility
subsidiaries, Nova Scotia Power Inc. and Bangor Hydro-Electric Company. Nova
Scotia Power supplies over 95% of the electric generation, transmission and
distribution in Nova Scotia. Nova Scotia Power's Point Tupper and Lingan
generating facilities have been ranked No. 1 and No. 2 in Canada in operating
performance by The Canadian Electricity Association. Bangor Hydro provides
electricity transmission and distribution service to 110,000 customers in
eastern Maine. It is a member of the New England Power Pool, and is
interconnected with the other New England utilities to the south and with
New Brunswick Power to the north. Emera also owns a 12.9% interest in the
Maritimes & Northeast Pipeline; Emera Energy Services which manages energy
assets on behalf of third parties and provides related services; and Emera
Fuels, which distributes home heating oil and related products to customers in
the Maritime provinces. Visit Emera on the web at www.emera.com.
Teleconference Call
Emera is holding a teleconference today at 5:00 pm Atlantic (4:00 pm
Toronto/Montreal/New York; 3:00 pm Winnipeg; 1:00 pm Vancouver) to discuss the
Q1, 2005 financial results. Analysts and other interested parties wanting to
participate in the call should dial 1-877-211-7911 (in Toronto 416-405-9310)
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 3148306 (available until midnight Tuesday,
May 10, 2005). The teleconference will also be web cast live at www.emera.com
and available for playback for one year.
Forward Looking Information
This news release contains forward looking information. Actual future
results may differ materially. Additional financial and operational
information is filed electronically with various securities commissions in
Canada through the System for Electronic Document Analysis and Retrieval
(SEDAR).
Management's Discussion & Analysis
As at May 3, 2005
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 first quarter of 2005 relative to 2004, and its
financial position at March 31, 2005. Certain factors that may impact future
operations are also discussed. Such comments will be affected by, and may
involve, known and unknown risks and uncertainties that may cause the actual
results of the company to be materially different from those expressed or
implied. Those risks and uncertainties include, but are not limited to,
weather, commodity prices, interest rates, foreign exchange, regulatory
requirements and general economic conditions.
This discussion and analysis should be read in conjunction with the Emera
Inc. unaudited consolidated financial statements and supporting notes as at
and for the three month period ended March 31, 2005, and the Emera Inc. MD&A
and annual audited consolidated financial statements and supporting notes as
at and for the year ended December 31, 2004. Emera follows Canadian Generally
Accepted Accounting Principles ("GAAP"). Emera's subsidiary, Nova Scotia Power
Inc.'s accounting policies are subject to examination and approval by the Nova
Scotia Utility and Review Board and are similar to those being used by other
companies in the electric utility industry in Canada. Emera's subsidiary,
Bangor Hydro-Electric Company's accounting policies are subject to examination
and approval by the Maine Public Utilities Commission and the Federal Energy
Regulatory Commission and are similar to those being used by other companies
in the electric utility industry in Maine. The rate-regulated accounting
policies of Nova Scotia Power and Bangor Hydro may differ from GAAP for non
rate-regulated companies.
Throughout this discussion, "Emera Inc." and "Emera" refer to Emera Inc.
and all of its consolidated subsidiaries and affiliates.
All amounts are in Canadian dollars ("CAD") except for Bangor Hydro,
which is reported in US dollars ("USD") unless otherwise stated.
Additional information related to Emera, including the company's Annual
Information Form, can be found at SEDAR at www.sedar.com.
INTRODUCTION
The core business of Emera is electricity. The company operates two
regulated electric utilities in northeastern North America, which together
comprise approximately 90% of consolidated revenues:
- Nova Scotia Power Inc. ("NSPI") is a wholly-owned, fully integrated,
regulated electric utility, with $3.0 billion of assets, serving
460,000 customers. NSPI is the primary electricity supplier in Nova
Scotia, providing the vast majority of the generation, transmission
and distribution of electricity in the province. NSPI is regulated by
the Nova Scotia Utility and Review Board ("UARB").
- Bangor Hydro-Electric Company ("BHE") is a wholly-owned regulated
electricity transmission and distribution company with $600 million of
assets serving over 110,000 customers in eastern Maine. BHE's
transmission operations are regulated by the Federal Energy Regulatory
Commission ("FERC"), and its distribution operations are regulated by
the Maine Public Utilities Commission ("MPUC").
The success of Emera's electric utilities is integral to the creation of
shareholder value, providing substantial earnings and cash flow. Both
utilities are regulated monopolies, which can generally be expected to result
in relatively stable earnings streams, but limits upside earnings potential,
all other things being equal. Accordingly, Emera looks beyond its existing
regulated electricity business to provide incremental growth.
Emera's plan for growth seeks to add energy infrastructure assets to its
portfolio. The company is focused on building on its core electricity
business, specifically in regulated transmission and distribution operations,
and low risk generation facilities. Emera is concentrating its efforts in
northeastern North America, which is continuing to develop as an integrated
energy market.
Structure of MD&A
This quarterly MD&A has been prepared in accordance with the Canadian
Securities Administrators National Instrument 51-102 Management's Discussion &
Analysis.
This Management's Discussion and Analysis begins with an overview of
quarterly consolidated results; then presents quarterly information on the
company's two primary subsidiaries, NSPI and BHE. All other operations,
including the Maritimes & Northeast Pipeline, Emera Energy Services, Emera
Fuels and corporate activities are grouped and discussed as "Other".
Significant changes in the consolidated balance sheets, outstanding share
data, liquidity and capital resources, financial and commodity instruments,
transactions with related parties, changes in accounting policies, and
selected quarterly trend information are presented on a consolidated basis.
<<
EMERA CONSOLIDATED
Q1 Operating Unit Contributions
(millions of dollars, except Three months ended
earnings per common share) March 31
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Nova Scotia Power $ 40.8 $ 38.8
Bangor Hydro-Electric 4.1 5.8
Other 3.4 1.9
-------------------------------------------------------------------------
Consolidated net earnings $ 48.3 $ 46.5
-------------------------------------------------------------------------
Earnings per common share - basic $ 0.44 $ 0.43
-------------------------------------------------------------------------
Earnings per common share - diluted $ 0.42 $ 0.41
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of Q1, 2005
Emera Inc.'s consolidated earnings increased $1.8 million, to
$48.3 million in Q1, 2005 compared to $46.5 million for the same period in
2004. Highlights of the earnings changes are summarized in the following
table:
(millions of dollars)
-------------------------------------------------------------------------
Consolidated net earnings, March 31, 2004 $ 46.5
Increased fuel expense in NSPI due to reduced natural gas
sales margin and higher coal prices (22.5)
Deferral of NSPI Q1 2005 taxes as approved by the UARB 15.3
Lower income taxes reflecting lower earnings before income
taxes 8.8
All other 0.2
-------------------------------------------------------------------------
Consolidated net earnings, March 31, 2005 $ 48.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q1 earnings per share were $0.44 in 2005, compared to $0.43 in 2004.
NOVA SCOTIA POWER INC.
Overview
2005 Rate Application
On March 31, 2005, the Nova Scotia Utility and Review Board rendered its
decision on Nova Scotia Power's 2005 rate application. The UARB granted NSPI
an average rate increase of approximately 5.3%, effective April 1, 2005. Other
key aspects of the decision include:
- full recovery of $150 million Section 21 income tax deposit over eight
years, commencing in 2007,
- an allowed Return on Equity of 9.55%, (formerly 10.15%)
- an allowed Common Equity Component of 37.5%, (formerly 35%)
- 10.4% increase effective January 1, 2005 for industrial customers with
annually adjusted rates, and
- delay of phase-in of $5 million increase in depreciation rates until
2006
The primary difference between NSPI's proposed rate settlement, and the
regulatory decision is an $18 million reduction in the allowed fuel expense.
The UARB also did not accept NSPI's proposal to defer $13 million of 2005 fuel
costs. The UARB expressed dissatisfaction with NSPI's fuel procurement
practice, saying that the company did not act quickly enough to implement
changes that had been previously directed by the UARB in 2002. However, as
acknowledged in their decision, the UARB did note that NSPI had a relatively
short period of time to take advantage of the decline in imported coal prices.
In February 2005, the UARB agreed to allow NSPI to defer new taxes, not
presently in rates, from January 1, 2005 until the date when new rates became
effective. Accordingly, NSPI has estimated a deferral of $15.3 million of
grants in lieu of taxes, provincial and federal capital taxes and income taxes
for the three months ended March 31, 2005. The amount of the deferral, and the
amortization period are subject to approval by the UARB.
The company has revised its financial outlook to incorporate the expected
effect of the rate case decision and the tax deferral. Net earnings for 2005
are expected to be approximately $22-$27 million lower than 2004, reflecting
substantially higher fuel costs, including the disallowance of fuel costs
referred to above, and the effect of the lower allowed return on equity.
Review of Q1, 2005
NSPI Q1 Net Earnings
(millions of dollars, except Three months ended
earnings per common share) March 31
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Electric revenue $ 260.2 $ 257.6
-------------------------------------------------------------------------
Fuel for generation and purchased power 104.6 82.1
Operating, maintenance and general 46.3 44.6
Provincial grants and taxes 10.1 9.4
Provincial grants and taxes deferral (4.9) -
Depreciation 29.5 29.5
Regulatory amortization 1.5 1.5
Other (2.0) (2.4)
-------------------------------------------------------------------------
Earnings before interest and income taxes 75.1 92.9
Interest 24.6 25.6
Amortization of defeasance costs 3.3 3.8
-------------------------------------------------------------------------
Earnings before income taxes 47.2 63.5
Income taxes 13.5 21.4
Income taxes deferral (10.4) -
-------------------------------------------------------------------------
Earnings before preferred dividends 44.1 42.1
Preferred dividends 3.3 3.3
-------------------------------------------------------------------------
Contribution to consolidated net earnings $ 40.8 $ 38.8
-------------------------------------------------------------------------
Contribution to consolidated earnings
per common share $ 0.37 $ 0.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's net earnings were $40.8 million in Q1, 2005, compared to
$38.8 million in Q1, 2004. Highlights of the earnings changes are summarized
in the following table:
(millions of dollars)
-------------------------------------------------------------------------
Contribution to consolidated net earnings, March 31, 2004 $ 38.8
Increased electric sales volumes, mitigated by a change in
the sales mix 2.6
Increased fuel expenses, due to reduced gas sales margin and
higher coal prices (22.5)
Deferral of Q1 2005 taxes, as approved by the UARB 15.3
Increased operating expenses, reflecting increased storm costs (1.7)
Decreased income taxes resulting from lower earnings 7.9
All other 0.4
-------------------------------------------------------------------------
Contribution to consolidated net earnings, March 31, 2005 $ 40.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q1 Electric Sales Volume Q1 Electric Sales Revenues
(GWh) (millions of dollars)
--------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
--------------------------------- ------------------------------------
Residential 1,288 1,307 1,286 Residential $123.1 $124.1 $122.5
Commercial 829 789 808 Commercial 70.5 67.6 69.6
Industrial 1,040 1,017 935 Industrial 56.7 56.2 51.4
Other 107 97 123 Other 9.9 9.7 9.8
--------------------------------- ------------------------------------
Total 3,264 3,210 3,152 Total $260.2 $257.6 $253.3
--------------------------------- ------------------------------------
--------------------------------- ------------------------------------
Q1 Average Revenue/MWh
----------------------------------------
2005 2004 2003
----------------------------------------
Dollars per MWh $80 $80 $80
----------------------------------------
----------------------------------------
Electric revenues increased $2.6 million, in Q1, 2005, to reach
$260.2 million, compared to $257.6 million in Q1, 2004, reflecting volume
increases in the commercial and industrial sector. Residential volumes were
slightly lower due to warmer temperatures, compared to a very cold Q1, 2004.
Outlook
The UARB has rendered its decision on Nova Scotia Power's 2005 rate
application, granting an average rate increase of approximately 5.3%,
effective April 1, 2005. The decision indicates an approximate $30-$35 million
increase in NSPI's annual revenue for 2005 compared to 2004.
Fuel for Generation and Purchased Power
Q1 Production Volume
(GWh)
----------------------------------------
2005 2004 2003
----------------------------------------
Coal and petcoke 2,483 2,532 2,456
Natural gas 41 36 21
Oil 550 604 543
Renewable 303 257 323
Purchased power 164 112 83
----------------------------------------
Total 3,541 3,541 3,426
----------------------------------------
----------------------------------------
Purchased power includes 20 GWh of wind power in 2005.
Q1 Average Unit Fuel Costs
----------------------------------------
2005 2004 2003
----------------------------------------
Dollars per MWh $30 $23 $23
----------------------------------------
----------------------------------------
For the three months ended March 31, 2005, fuel for generation and
purchased power was $104.6 million, compared to $82.1 million in Q1, 2004.
Highlights of the changes are summarized in the following table:
(millions of dollars)
-------------------------------------------------------------------------
Fuel for generation and purchased power, March 31, 2004 $ 82.1
Lower net proceeds from the resale of natural gas due to
lower volumes and higher pricing of the supply contract 14.7
Increased commodity pricing including change in the fuel mix to
meet environmental requirements 14.7
Increased renewable production volumes (3.2)
All other (3.7)
-------------------------------------------------------------------------
Fuel for generation and purchased power, March 31, 2005 $ 104.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company's natural gas supply contract was subject to a price
re-opening effective November 1, 2004, which will change the purchase price.
This contract is currently in binding arbitration. During the arbitration
period, natural gas purchases are recorded based on management's best estimate
of the new contract price. The company continues to pay for gas purchases
based on the old pricing. The difference between the old price and
management's best estimate of the new contract price is included in Accounts
Payable and Accrued Charges and will be paid to the supplier once the new
contract price has been settled by arbitration. The company expects a final
decision by Q4, 2005, which may result in a price different from management's
estimate. Management is unable to predict the outcome of this arbitration and
the effect it may have on fuel for generation and purchased power expense,
financial results, cash flows or financial position.
The arbitration process has also triggered a price adjustment clause
covering the next three years of natural gas purchases. NSPI is entitled to
one-third of the contracted gas supply at a fixed price, with the remainder
subject to the future contract price. However, the company will pay for all
gas purchases at the future contract price, and the accumulated difference
between the fixed price and the future contract price on one-third of the gas
purchases will be settled in November 2007. This amount is recorded in
Deferred Charges and Other Receivables with an offset to the fuel for
generation and purchased power expense.
Provincial Grants and Taxes
Provincial grants and taxes increased $0.7 million in Q1, 2005, to
$10.1 million, compared to $9.4 million in Q1, 2004, reflecting the increase
in the provincial capital tax rate from 0.25% to 0.3%, effective April 1, 2004
as well as inflationary adjustments to provincial grants.
As previously noted, the UARB had agreed to allow NSPI to defer new taxes
not presently in rates in 2005 until new rates became effective. Accordingly,
NSPI has deferred an estimated $4.9 million of grants in lieu of taxes and
provincial capital taxes to March 31, 2005, reflecting increases in these
taxes since rates were last set in 2002.
Regulatory Amortization
The Glace Bay generating station has been permanently shut down, and is
being written off through 2008, if required, at an annually minimum rate of
$6.2 million. In the first quarter of 2005, $1.5 million has been recognized
(Q1, 2004 - $1.5 million). The amount remaining to be written off is
$16.6 million.
Interest
Interest expense decreased $1.0 million, to $24.6 million in Q1, 2005,
compared to $25.6 million in Q1, 2004, due to the refinancing of a
$140 million mid-term note with short-term debt in Q1, 2004.
Income Taxes
As previously noted, the UARB had agreed to allow NSPI to defer new taxes
not presently in rates in 2005 until new rates became effective. Accordingly,
NSPI has deferred an estimated $10.4 million of federal capital taxes and
income taxes to March 31, 2005, reflecting increases in these taxes since
rates were last set in 2002.
NSPI has a $150 million regulatory asset related to pre-2003 income taxes
that have been paid, but not yet recovered from customers. This circumstance
arose because NSPI had claimed deductions that were ultimately disallowed by
the Supreme Court of Canada.
In its decision on NSPI's 2005 rate application, the UARB has provided
for amortization and recovery of this regulatory asset over eight years,
commencing in 2007.
Debt Management
In February 2004, a $140 million 7.3% mid-term note matured and was
refinanced with short-term debt.
Outlook
As previously mentioned, the company has revised its financial outlook to
incorporate the expected effect of the rate case decision and the tax
deferral. Net earnings for 2005 are expected to be approximately
$22-$27 million lower than 2004, reflecting substantially higher fuel costs,
including the disallowance of fuel costs referred to above, and the effect of
the lower allowed return on equity. As a result, Nova Scotia Power expects to
earn a regulated return on equity below its allowed range.
Fuel costs are expected to remain high. The company is currently
reviewing its financial forecast for 2006, and will make a decision in Q2 as
to whether a rate application for 2006 will be filed.
BANGOR HYDRO-ELECTRIC COMPANY
Since the restructuring of the electricity sector in Maine in 2000, BHE's
core business has been the transmission and distribution ("T&D") of
electricity. Electricity generation is deregulated in Maine, and several
suppliers compete to provide customers with the commodity that is delivered
through the BHE T&D network.
All amounts in the Bangor Hydro section are reported in US dollars unless
otherwise stated.
Review of Q1, 2005
Bangor Hydro Q1 Net Earnings
(millions of dollars, except Three months ended
earnings per common share) March 31
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
T&D revenues $ 29.3 $ 31.2
Resale of purchased power 2.2 4.4
-------------------------------------------------------------------------
Total electric revenue 31.5 35.6
Purchased power and fuel for generation 8.0 11.5
Operating, maintenance and general 8.0 7.5
Property taxes 1.4 1.3
Depreciation 3.1 2.7
Regulatory amortization 3.9 3.0
Other (0.9) (0.6)
-------------------------------------------------------------------------
Earnings before interest and income taxes 8.0 10.2
Interest 2.5 2.8
-------------------------------------------------------------------------
Earnings before income taxes 5.5 7.4
Income taxes 2.2 3.0
-------------------------------------------------------------------------
Contribution to consolidated net earnings - US $ $ 3.3 $ 4.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated net earnings -
Canadian $ $ 4.1 $ 5.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated earnings per common
share - Canadian $ $ 0.04 $ 0.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted average foreign exchange
rate - Canadian/US $ $ 1.2248 $ 1.3119
Bangor Hydro's contribution to consolidated net earnings was
$3.3 million USD in Q1, 2005, compared to $4.4 million USD in Q1, 2004.
Highlights of the earnings changes are summarized in the following table:
(millions of US dollars)
-------------------------------------------------------------------------
Contribution to consolidated net earnings, March 31, 2004 $ 4.4
Lower electric revenue due to reduced residential and
commercial sales (0.7)
Increased operating, maintenance and general expense (0.5)
All other 0.1
-------------------------------------------------------------------------
Contribution to consolidated net earnings, March 31, 2005 $ 3.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was
$4.1 million CAD in Q1, 2005 compared to $5.8 million CAD in Q1, 2004, due to
the Canadian dollar equivalent of the variances discussed above.
Electric Revenue
Q1 T&D Sales Volume Q1 T&D Sales Revenues
(GWh) (millions of US dollars)
--------------------------------- ------------------------------------
2005 2004 2003 2005 2004 2003
--------------------------------- ------------------------------------
Residential 160 165 161 Residential $14.2 $15.1 $14.5
Commercial 150 155 151 Commercial 9.9 10.9 11.1
Industrial 98 70 96 Industrial 3.9 3.9 4.5
Other 3 3 3 Other 1.3 1.3 1.1
--------------------------------- ------------------------------------
Total 411 393 411 Total $29.3 $31.2 $31.2
--------------------------------- ------------------------------------
--------------------------------- ------------------------------------
BHE's electric revenues decreased by $1.9 million in Q1, 2005, to
$29.3 million compared to $31.2 million in Q1, 2004. Highlights of the quarter
over quarter changes are summarized in the following table:
(millions of US dollars)
-------------------------------------------------------------------------
T&D revenues, March 31, 2004 $ 31.2
Lower electric revenue due to reduced residential and
commercial sales (0.7)
Lower stranded costs rates (substantially offset as discussed
in Outlook below) (1.4)
All other 0.2
-------------------------------------------------------------------------
T&D revenues, March 31, 2005 $ 29.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Outlook
On February 25, 2005, the Maine Public Utilities Commission issued an
Order approving changes to BHE's stranded cost rates for the three-year period
March 1, 2005 to February 29, 2008. The stranded cost rates were reduced by
approximately 37%, which represents an approximately 15% to 20% reduction in
total electric rates. The reduction is driven by the completion of a major
regulatory amortization, and increases in the rate at which BHE's power
purchases under long-term power supply agreements will be resold to a third
party. Accordingly, net earnings are expected to decrease only marginally.
Operating, Maintenance and General Expenditures
Operating expenses were $0.5 million higher in Q1, 2005 at $8.0 million
compared to $7.5 million in Q1, 2004 primarily due to lower capital
allocations.
Regulatory Amortization
Amortization expense was $0.9 million higher in Q1, 2005 at $3.9 million,
compared to $3.0 million in Q1, 2004, reflecting the completion of
amortization on certain regulatory liabilities in Q1, 2004, offset by new
amortizations starting March 1, 2005 in connection with new stranded cost
rates.
Interest
BHE's interest expense decreased to $2.5 million in Q1, 2005 from
$2.8 million in Q1, 2004 due principally to long-term debt repayments in 2004.
Regulatory Matters
When it acquired Bangor Hydro in 2001, Emera became a registered public
utility holding company under the Public Utility Holding Company Act
("PUHCA"). PUHCA is administered by the U.S. Securities and Exchange
Commission ("SEC"). In the normal course of regulating registered public
utility holding companies, the SEC audits and/or reviews each registrant's
compliance with PUHCA approximately once every five years. The SEC audit of
Emera began in the fall of 2004. No significant issues have been identified to
date and the SEC had not yet issued its final report.
OTHER
All activities of Emera outside of its two regulated electric utilities
are incorporated in other, including:
- Emera Energy Services, which manages energy assets on behalf of third
parties and provides related energy management services. Energy
Services operates with minimal day-to-day commodity risk exposure.
- A 12.9% interest in the $2 billion, 1,300 kilometre Maritimes &
Northeast Pipeline ("M&NP") that transports Nova Scotia's offshore
natural gas to markets in Maritime Canada and the northeastern United
States.
- Emera Fuels, an unregulated subsidiary that distributes home heating
oil, heavy fuel oil, lubricants and related products to over 22,000
customers in the Maritime provinces.
- Certain corporate-wide functions such as strategic planning, treasury
services, tax planning, and corporate governance; and financing for
the corporation's business outside of its electric utilities.
Review of Q1, 2005
Other Q1 Net Earnings
(millions of dollars, except Three months ended
earnings per common share) March 31
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Fuel oil sales $ 29.2 $ 29.1
M&NP equity earnings 1.8 2.1
Energy marketing margin 7.3 9.9
-------------------------------------------------------------------------
38.3 41.1
-------------------------------------------------------------------------
Cost of fuel oil sold 24.7 24.1
Operating, maintenance and general 7.7 7.9
Business development (0.2) 3.1
Depreciation 0.6 0.7
Other (1.0) (0.9)
-------------------------------------------------------------------------
Earnings before interest and income taxes 6.5 6.2
Interest 2.6 4.1
-------------------------------------------------------------------------
Earnings before income taxes 3.9 2.1
Income taxes 0.5 0.2
-------------------------------------------------------------------------
Contribution to consolidated net earnings $ 3.4 $ 1.9
-------------------------------------------------------------------------
Contribution to consolidated earnings
per common share $ 0.03 $ 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The contribution of Other operations to consolidated net earnings
increased $1.5 million quarter over quarter. Highlights of the quarter over
quarter changes are summarized in the following table:
(millions of dollars)
-------------------------------------------------------------------------
Contribution to consolidated net earnings, March 31, 2004 $ 1.9
Lower energy marketing margin (2.6)
Write-off of Greyhawk Gas Storage joint venture in Q1, 2004 1.9
Lower interest expense 1.5
All other 0.7
-------------------------------------------------------------------------
Contribution to consolidated net earnings, March 31, 2005 $ 3.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gross Margin on Fuel Oil Sales
Emera Fuels' gross margin was $4.5 million in Q1, 2005, compared to
$5.0 million in Q1, 2004 primarily due to the continued high cost of the
commodity. This has resulted in competitive pressures within the cash markets
as well as lower gross margins on the fixed price program.
Equity Earnings
Equity earnings from the Maritimes & Northeast Pipeline were $1.8 million
in Q1, 2005 compared to $2.1 million in Q1, 2004. Increases in the tolls
collected for its US operations have been more than offset by lower volumes
and the impact of the stronger Canadian dollar on the US portion of the
pipeline.
In 2004 M&NP filed a Notice of Rate Increase for its US operations.
In August 2004 MN&P received approval from its regulator to collect
proposed rates beginning January 1, 2005, pending regulatory approval of new
rates. Any amounts collected in excess of the new rates, once approved, will
be returned to customers. In Q1, 2005 the company recognized its best estimate
of $2.0 million in equity earnings and energy marketing margin pertaining to
the new rates.
Energy Marketing Margin
Emera Energy Services net margin decreased to $7.3 million in Q1, 2005,
from $9.9 million in Q1, 2004 as a result of decreased natural gas marketing
opportunities.
Business Development
Business development costs were $(0.2) million in Q1, 2005, compared to
$3.1 million in Q1, 2004, reflecting the write-off in Q1, 2004 of Emera's
$1.9 million investment in the Greyhawk Gas Storage joint venture, a portion
of which was subsequently recovered in 2005; and the deferral of business
development expenses related to the pending acquisitions of two hydro
generation facilities.
Interest
Interest expense was $2.6 million in Q1, 2005 compared to $4.1 million in
Q1, 2004 largely as a result of the impact of a stronger Canadian dollar on
the company's US dollar denominated financial commitments.
Consolidated Balance Sheets
Significant changes in the consolidated balance sheets between March 31,
2005 and December 31, 2004 include:
- $12.3 million decrease in restricted cash, reflecting the seasonality
of energy marketing business.
- $27.5 million increase in accounts receivable, reflecting the
seasonality of revenues and a decrease in the amount of accounts
receivable securitized.
- $13.0 million increase in prepaid expenses, reflecting the timing of
the payment of the provincial grants in lieu.
- $8.3 million increase in deferred charges and other receivables,
reflecting the deferral of taxes, the increase in the amount
receivable from the price adjustment clause in the supply contract in
arbitration, and amortization of regulatory and other deferred assets.
- $22.6 million decrease in accounts payable and accrued charges,
reflecting the timing of payments offset by the increase in fuel
related payables due to the arbitration of a supply contract, lower
BHE power purchases, and lower posted margin.
Outstanding Share Data
Common
Issued and Outstanding: Millions of Share
(millions of dollars) Shares Capital
-------------------------------------------------------------------------
January 1, 2004 108.26 $ 1,008.4
Issued for cash under purchase plans 0.41 7.0
Options exercised under senior management share
option plan 0.20 2.8
Share-based compensation - 1.0
-------------------------------------------------------------------------
December 31, 2004 108.87 $ 1,019.2
Issued for cash under purchase plans 0.10 2.0
Options exercised under senior management share
option plan 0.13 2.1
Share-based compensation - 0.2
-------------------------------------------------------------------------
March 31, 2005 109.10 $ 1,023.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liquidity and Capital Resources
In Q1, 2005 Emera and Nova Scotia Power established debt shelf
prospectuses in the amounts of $300 million and $400 million respectively that
provide the companies with access to long-term debt. The prospectuses expire
in April 2007.
Consolidated Cash Flow Highlights
Three months ended
(millions of dollars) March 31
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Net cash provided by operating activities $ 18.0 $ 55.7
Net cash used in financing activities (20.8) (34.5)
Net cash used in investing activities (9.6) (11.2)
-------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents $ (12.4) $ 10.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash provided by operating activities was $18.0 million
in Q1, 2005, compared to $55.7 million in Q1, 2004 reflecting NSPI's increased
fuel costs and working capital changes.
Consolidated net cash used in financing activities decreased
$13.7 million quarter over quarter reflecting debt maturities in Q1, 2004 less
short-term debt issued to refinance, and a reduction in the level of accounts
receivable securitized in Q1, 2005.
Financial and Commodity Instruments
The Company manages its exposure to foreign exchange, interest rate, and
commodity risks in accordance with established risk management policies and
procedures. The Company uses derivative instruments consisting mainly of
foreign exchange forward contracts, interest options and swaps, and oil and
gas options and swaps.
Hedges that meet stringent documentation requirements, and can be proven
to be effective both at the inception and over the term of the instrument
qualify for hedge accounting. Specifically, amounts paid or received are
deferred and recognized in earnings in the same period the related hedged item
is realized. Where the documentation or effectiveness requirements are not
met, the non-qualifying hedges are marked to market and recognized in earnings
in the reporting period.
The Company has deferred payments and receipts on derivative instruments
that are designated and effective as hedges and are recognized in the
following categories in the balance sheet:
Deferred Hedging Losses (Gains) Recognized on the Balance Sheet
(millions of dollars)
-------------------------------------------------------------------------
March 31 December 31
2005 2004
-------------------------------------------------------------------------
Deferred charges $ 0.1 $ 0.1
Inventory 0.4 1.6
Accounts payable and accrued charges (0.2) (0.3)
-------------------------------------------------------------------------
Deferred hedging losses $ 0.3 $ 1.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three-month periods ended March 31, the impacts of effective
hedges recognized in earnings were recorded in the following categories:
Hedging Impact Recognized in Earnings
(millions of dollars)
-------------------------------------------------------------------------
Q1 2005 Q1 2004
-------------------------------------------------------------------------
Fuel and purchased power increase $ (3.7) $ (5.7)
Interest expense increase (0.5) (1.6)
-------------------------------------------------------------------------
Hedging earnings impact $ (4.2) $ (7.3)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Company also enters into non-hedging derivative financial and
commodity instruments. These instruments, along with the non-qualifying hedges
referred to above, are marked-to-market at each reporting date.
The Company had recorded the following mark-to-market transactions
included in the balance sheet and recognized in earnings.
Mark-to-Market Gains (Losses) Recognized on the Balance Sheet
(millions of dollars)
-------------------------------------------------------------------------
March 31 December 31
2005 2004
-------------------------------------------------------------------------
Energy marketing assets $ 4.7 $ 10.3
Energy marketing liabilities (4.4) (9.4)
-------------------------------------------------------------------------
Mark-to-market gains $ 0.3 $ 0.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Mark-to-Market Gains (Losses) Recognized in Earnings
(millions of dollars)
-------------------------------------------------------------------------
Q1 2005 Q1 2004
-------------------------------------------------------------------------
Other revenue $ (0.6) $ 0.3
Fuel and purchased power - (5.6)
-------------------------------------------------------------------------
Mark-to-market losses $ (0.6) $ (5.3)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In determining the fair value of derivative financial instruments, the
Company has relied on quoted market prices as at the date of valuation.
Transactions With Related Parties
During the quarter, in the ordinary course of business, Emera purchased
transportation capacity totaling $9.8 million (2004 - $12.0 million) from the
Maritimes & Northeast Pipeline, an investment under significant influence of
the Company. The amount is recognized in fuel for generation, or netted
against energy marketing margin in other revenue, and is measured at the
exchange amount. At March 31, 2005 the amount payable to the related party is
$3.3 million (December 31, 2004 - $3.2 million), and is noninterest bearing
and is under normal credit terms.
Change in Accounting Policies
Variable Interest Entities
In June 2003, the Canadian Institute of Chartered Accountants issued
Accounting Guideline 15 Consolidation of Variable Interest Entities. This
guideline applies to annual and interim periods beginning on or after
November 1, 2004. A variable interest entity ("VIE") is any type of legal
structure in which control is determined through contractual or other
financial arrangements as opposed to traditional voting rights, if certain
conditions exist. The guideline requires the enterprise which absorbs the
majority of a VIE's expected losses or receives the majority of a VIE's
expected residual returns, the primary beneficiary, to consolidate the VIE.
The Company has variable interests in VIEs that are not consolidated
because the Company is not considered the primary beneficiary. These variable
interests consist of purchase power agreements for renewable energy with
independent power producers. The Company's only obligation under these
agreements is to purchase all of the energy produced, which currently is
expected to approximate 100 GWh annually. The Company is not exposed to any
significant loss from these agreements because the cost of these power
purchases is recoverable through rates. The Company will continue to monitor
any new developments that may affect our current evaluation of these
agreements.
Summary of Quarterly Reports
For the quarter ended
(millions of dollars, except earnings per common share)
-------------------------------------------------------------------------
Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
2005 2004 2004 2004 2004 2003 2003 2003
-------------------------------------------------------------------------
Total revenues $338.9 $309.4 $276.0 $287.2 $347.4 $310.3 $281.0 $284.8
Net earnings
applicable to
common shares $48.3 $31.4 $22.1 $29.8 $46.5 $47.5 $11.5 $15.5
Earnings per
common share -
basic $0.44 $0.30 $0.20 $0.27 $0.43 $0.44 $0.11 $0.14
Earnings per
common share -
diluted $0.42 $0.28 $0.20 $0.27 $0.41 $0.43 $0.11 $0.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Quarterly total revenues and net earnings applicable to common shares are
affected by seasonality, with Q1 and Q4 the strongest periods, reflecting
colder weather and fewer daylight hours at those times of year.
Financial Statements
Consolidated Statements of Earnings (Unaudited)
For the three months ended March 31
(millions of dollars, except earnings per common share)
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Revenue
Electric $ 299.0 $ 305.8
Fuel oil 29.2 28.6
Other 10.7 13.0
-------------------------------------------------------------------------
338.9 347.4
-------------------------------------------------------------------------
Cost of operations
Fuel for generation and purchased power 114.4 97.8
Cost of fuel oil sold 24.7 23.7
Operating, maintenance and general 63.6 65.5
Provincial, state, and municipal taxes 12.0 11.4
Provincial tax deferral (note 8) (4.9) -
Depreciation 34.0 33.8
-------------------------------------------------------------------------
243.8 232.2
-------------------------------------------------------------------------
Earnings from operations 95.1 115.2
Equity earnings (note 6) 1.8 2.1
Regulatory amortization (6.2) (5.5)
Allowance for funds used during construction 0.8 0.7
-------------------------------------------------------------------------
Earnings before interest and income taxes 91.5 112.5
Interest (note 7) 30.3 33.4
Amortization of defeasance costs 3.3 3.8
-------------------------------------------------------------------------
Earnings before income taxes 57.9 75.3
Income taxes 16.7 25.5
Income taxes deferral (note 8) (10.4) -
-------------------------------------------------------------------------
Net earnings before non-controlling interest 51.6 49.8
Non-controlling interest 3.3 3.3
-------------------------------------------------------------------------
Net earnings applicable to common shares $ 48.3 $ 46.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - basic $ 0.44 $ 0.43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share - diluted $ 0.42 $ 0.41
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Weighted average number of common shares
outstanding (millions) - basic 109.1 108.3
Weighted average number of common shares
outstanding (millions) - diluted 122.5 122.2
Consolidated Statements of Retained Earnings (Unaudited)
For the three months ended March 31
(millions of dollars)
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Retained earnings, beginning of year $ 399.6 $ 365.3
Net earnings applicable to common shares 48.3 46.5
-------------------------------------------------------------------------
447.9 411.8
Dividends 24.2 23.8
-------------------------------------------------------------------------
Retained earnings, end of period $ 423.7 $ 388.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Consolidated Balance Sheets (Unaudited)
As at
(millions of dollars)
-------------------------------------------------------------------------
March 31 December 31
2005 2004
-------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 30.3 $ 42.7
Restricted cash 5.9 18.2
Accounts receivable 203.6 176.1
Income tax receivable 6.6 2.4
Inventory 70.0 73.4
Prepaid expenses 18.4 5.4
Future income tax assets 4.0 3.6
Energy marketing assets 4.7 10.3
-------------------------------------------------------------------------
343.5 332.1
-------------------------------------------------------------------------
Long-term receivable 20.0 20.0
-------------------------------------------------------------------------
Deferred charges and other receivables (note 9) 588.5 580.2
-------------------------------------------------------------------------
Future income tax assets 33.1 34.1
-------------------------------------------------------------------------
Goodwill 108.2 107.7
-------------------------------------------------------------------------
Investments (note 10) 99.7 96.8
-------------------------------------------------------------------------
Property, plant & equipment 2,704.2 2,714.6
Construction work in progress 70.0 63.7
-------------------------------------------------------------------------
2,774.2 2,778.3
-------------------------------------------------------------------------
$ 3,967.2 $ 3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities & Shareholders' Equity
Current liabilities
Current portion of long-term debt $ 100.4 $ 100.8
Short-term debt 143.6 145.4
Accounts payable and accrued charges 210.8 233.4
Income tax payable 2.9 1.4
Dividends payable 3.2 3.2
Energy marketing liabilities 4.4 9.4
-------------------------------------------------------------------------
465.3 493.6
-------------------------------------------------------------------------
Future income tax liabilities 82.2 82.2
-------------------------------------------------------------------------
Asset retirement obligations 69.4 68.5
-------------------------------------------------------------------------
Deferred credits 80.3 80.8
-------------------------------------------------------------------------
Long-term debt (note 11) 1,642.7 1,626.5
-------------------------------------------------------------------------
Non-controlling interest 260.8 260.8
-------------------------------------------------------------------------
Shareholders' equity
Common shares 1,023.5 1,019.2
Foreign exchange translation adjustment (80.7) (82.0)
Retained earnings 423.7 399.6
-------------------------------------------------------------------------
1,366.5 1,336.8
-------------------------------------------------------------------------
$ 3,967.2 $ 3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contingencies (Note 14)
See accompanying notes to the unaudited consolidated financial
statements.
Approved on behalf of the Board of Directors
Derek Oland Chris Huskilson
Chairman President and Chief Executive Officer
Consolidated Statements of Cash Flow (Unaudited)
For the three months ended March 31
(millions of dollars)
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Operating activities
Net earnings before non-controlling interest $ 51.6 $ 49.8
Non-cash items:
Depreciation 34.0 33.8
Deferral of provincial taxes and income taxes (15.3) -
Amortization of deferred charges 7.7 15.9
Equity earnings (1.8) (2.1)
Regulatory amortization 6.2 5.5
Allowance for funds used during construction (0.8) (0.7)
Future income taxes 0.2 (5.4)
Other cash operating items (6.8) (2.3)
-------------------------------------------------------------------------
Operating cash flow 75.0 94.5
Change in non-cash operating working capital (57.0) (38.8)
-------------------------------------------------------------------------
Net cash provided by operating activities 18.0 55.7
-------------------------------------------------------------------------
Financing activities
Retirements of long-term debt (1.2) (141.0)
Increase in short-term debt 14.1 132.1
Issue of common shares 4.1 2.1
Dividends on common shares (24.2) (23.8)
Dividends paid by subsidiaries to
non-controlling interest (3.3) (3.4)
Accounts receivable securitization (10.0) -
Other financing (0.3) (0.5)
-------------------------------------------------------------------------
Net cash used in financing activities (20.8) (34.5)
-------------------------------------------------------------------------
Investing activities
Property, plant and equipment (19.7) (14.6)
Investments (1.5) (0.8)
Retirement spending net of salvage (0.7) (0.6)
Decrease in restricted cash 12.3 4.8
-------------------------------------------------------------------------
Net cash used in investing activities (9.6) (11.2)
-------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (12.4) 10.0
Cash and cash equivalents, beginning of year 42.7 10.0
-------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 30.3 $ 20.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents consists of:
Cash $ 27.7 $ 20.0
Short-term investments 2.6 -
-------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 30.3 $ 20.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental disclosure of cash paid:
Interest $ 29.6 $ 36.6
Income and capital taxes $ 12.1 $ 23.8
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Notes to the Interim Unaudited Consolidated Financial Statements
March 31, 2005
1. Basis of Presentation
The disclosures in these unaudited interim consolidated financial
statements do not conform in all respects to the requirements of
Canadian generally accepted accounting principles for annual
financial statements and should be read in conjunction with
Emera Inc.'s annual consolidated financial statements as at and for
the year ended December 31, 2004.
These consolidated financial statements follow the same accounting
policies and methods of computation as Emera Inc.'s annual
consolidated financial statements as at and for the year ended
December 31, 2004 with the exception of the accounting policy change
disclosed in note 3.
2. Seasonal Nature of Operations
Interim results are not necessarily indicative of results for the
full year due primarily to seasonal factors. Sales and related
production change significantly over the year, with Q1 and Q4
reflecting colder weather and fewer daylight hours in the winter
season.
3. Change in Accounting Policies
Variable interest entities
In June 2003, the Canadian Institute of Chartered Accountants
("CICA") issued Accounting Guideline 15 Consolidation of Variable
Interest Entities. This guideline applies to annual and interim
periods beginning on or after November 1, 2004. A variable interest
entity ("VIE") is any type of legal structure in which control is
determined through contractual or other financial arrangements as
opposed to traditional voting rights, if certain conditions exist.
The guideline requires the enterprise which absorbs the majority of a
VIE's expected losses or receives the majority of a VIE's expected
residual returns, the primary beneficiary, to consolidate the VIE.
The Company has variable interests in VIEs that are not consolidated
because the Company is not considered the primary beneficiary. These
VIEs include purchase power agreements for renewable energy with
independent power producers. The Company's only obligation under
these agreements is to purchase all of the energy produced, which
currently is expected to approximate 100 GWh annually. The Company is
not exposed to any loss from these agreements because the cost of
these power purchases is recoverable through rates. The Company will
continue to monitor any new developments that may affect our current
evaluation of these agreements.
4. Segment Information
Segmented financial information for the three months ended and as at
March 31, 2005:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external customers $261.7 $39.4 $37.8 $338.9
Depreciation 29.5 3.9 0.6 34.0
Cost of operations, including
depreciation 185.6 25.2 33.0 243.8
Net intersegment operating
revenues/(expenses) 32.5 (0.7) (31.8) -
Equity earnings - - 1.8 1.8
Interest expense 24.6 3.1 2.6 30.3
Income taxes 13.5 2.7 0.5 16.7
Net earnings applicable to
common shareholders 40.8 4.1 3.4 48.3
Segment assets 3,029.7 598.6 338.9 3,967.2
Segment goodwill - 99.8 8.4 108.2
Capital expenditures 11.2 8.5 - 19.7
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented financial information for the three months ended and as at
March 31, 2004:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external customers $259.3 $47.7 $40.4 $347.4
Depreciation 29.5 3.6 0.7 33.8
Cost of operations, including
depreciation 165.6 30.4 36.2 232.2
Net intersegment operating
revenues/(expenses) 45.7 (0.6) (45.1) -
Equity earnings - - 2.1 2.1
Interest expense 25.6 3.7 4.1 33.4
Income taxes 21.4 3.9 0.2 25.5
Net earnings applicable to
common shareholders 38.8 5.8 1.9 46.5
Segment assets 2,990.2 666.4 284.2 3,940.8
Segment goodwill - 108.2 8.4 116.6
Capital expenditures 10.3 3.7 0.6 14.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(x) Other consists of items related to corporate activities and other
subsidiaries.
5. Employee Future Benefits
Emera maintains contributory defined-benefit and defined-contribution
pension plans, which cover substantially all of its employees, and
plans that provide non-pension benefits for its retirees. The
Company's cost, related to these plans, for the three-month period
ended March 31, 2005 is $7.3 million (2004 - $7.9 million).
6. Equity Earnings
For the three months ended March 31, 2005, equity earnings of
$1.8 million (2004 - $2.1 million) consists of the Company's pro-rata
portion of after-tax earnings from Maritimes and Northeast Pipeline,
an investment under significant influence of the Company.
7. Interest
Interest expense consists of the following:
Three months ended
March 31
---------------------------------------------------------------------
(millions of dollars) 2005 2004
---------------------------------------------------------------------
Interest on long-term debt $26.8 $29.2
Interest on short-term debt 3.3 3.3
Amortization of debt financing 0.3 0.2
Foreign exchange (gains) losses (0.1) 0.7
---------------------------------------------------------------------
$30.3 $33.4
---------------------------------------------------------------------
---------------------------------------------------------------------
8. Provincial Tax Deferral and Income Tax Deferral
The UARB approved NSPI's request to defer new taxes not presently in
rates from January 1, 2005 until the date when rates allowed by the
UARB in the 2005 Rate Application became effective. On March 31,
2005, the UARB granted NSPI a rate increase effective April 1, 2005.
As a result, the Company has estimated a deferral of $15.3 million of
grants in lieu of taxes, provincial and federal capital taxes and
income taxes for the three months ended March 31, 2005. The actual
amount of the deferral and the amortization period remains to be
determined by the UARB.
9. Deferred Charges and Other Receivables
On June 11, 2004, the Supreme Court of Canada dismissed Nova Scotia
Power's appeal to allow income tax deductions NSPI had claimed
between 1998 and 2002. The deductions represented approximately
$129 million in income tax otherwise payable ($150 million including
interest).
NSPI deposited the amount owing with the Canada Revenue Agency in
2001 and 2003 in order to avoid incurring non-deductible interest
charges in the event its Supreme Court appeal was unsuccessful. The
UARB provided an accounting order allowing NSPI to defer this amount
while the matter was settled before the Supreme Court.
In its March 31, 2005 decision on NSPI's 2005 rate application, the
UARB has approved the amortization and recovery of the tax deposit
over eight years, commencing in 2007.
10. Investments
Investments are comprised of the following:
March 31 December 31
(millions of dollars) 2005 2004
---------------------------------------------------------------------
Equity accounted investments
Maritimes & Northeast Pipeline $90.8 $88.0
Maine Yankee Atomic Power Company 3.1 3.1
Maine Electric Power Company Inc. 1.5 1.4
Intragas Energy 1.9 1.9
---------------------------------------------------------------------
Total equity investments 97.3 94.4
Long-term portfolio investments 2.4 2.4
---------------------------------------------------------------------
$99.7 $96.8
---------------------------------------------------------------------
---------------------------------------------------------------------
11. Long-Term Debt
Long-term debt includes a private placement in the amount of
$10.0 million (December 31, 2004 - $10.0 million), which is secured
by a letter of credit.
12. Common Shares and Non-Controlling Interest
As of March 31, 2005 there were 109,104,497 (December 31, 2004 -
108,865,616) issued and outstanding common shares, 953,259
(December 31, 2004 - 1,083,759) common shares reserved for issuance
under the senior management common share option plan, and 1,363,137
(December 31, 2004 - 1,403,376) common shares reserved for issuance
under the employee common share purchase plan.
During the three months ended March 31, 2005, the Company issued
238,881 (2004 - 129,685) common shares for cash proceeds of
$4.1 million (2004 - $2.1 million). Additionally, $0.2 million
(2004 - $0.3 million) was recognized as share compensation. Common
shares were issued through the employee common share purchase plan,
the senior management common share option plan, and the dividend
reinvestment plan.
As of March 31, 2005 and December 31, 2004 the Company's principal
subsidiary, Nova Scotia Power Inc., had outstanding the following
First Preferred Share Units:
- 4,998,695 4.9% Series C, which if not redeemed, in whole or in
part, by Nova Scotia Power Inc. on or after April 1, 2009, will
be exchangeable into common shares of Emera Inc.
- 5,400,000 5.9% Series D, which if not redeemed, in whole or in
part, by Nova Scotia Power Inc. on or after October 15, 2015,
will be exchangeable into common shares of Emera Inc.
As of March 31, 2005 the Company's subsidiary, Bangor Hydro-Electric
Company, had outstanding the following Preferred Share Units:
- 6,266 (December 31, 2004 - 6,276) non-callable, 7% preferred
shares.
13. Related Party Transactions
During the three months ended March 31, 2005, in the ordinary course
of business, the Company purchased transportation capacity totaling
$9.8 million (2004 - $12.0 million) from the Maritimes & Northeast
Pipeline, an investment under significant influence of the Company.
The amount is recognized in fuel for generation and purchased power
or netted against energy marketing margin in other revenue, and is
measured at the exchange amount. As at March 31, 2005 the amount
payable to the related party is $3.3 million (December 31, 2004 -
$3.2 million), and is non-interest bearing and is under normal credit
terms.
14. Contingencies
In August 2004 MN&P received approval from its regulator to collect
proposed rates beginning January 1, 2005, pending regulatory approval
of new rates. Any amounts collected in excess of the new rates, once
approved, will be returned to customers. In Q1, 2005 the Company
recognized its best estimate of $2.0 million in equity earnings and
energy marketing margin pertaining to the new rates.
15. Comparative Information
Certain of the comparative figures have been reclassified to conform
to the consolidated financial statement presentation adopted for
2005.
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