HALIFAX, July 27 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net
earnings were $19.3 million in Q2, 2005, down from $29.8 million in Q2, 2004.
The decrease reflects a 45% drop in earnings for the Company's largest
subsidiary, Nova Scotia Power (NSPI). NSPI contributed $13.7 million to
Emera's consolidated net earnings in the second quarter of this year, down
from $25.0 million for the same period last year.
The $11.3 million decrease in NSPI's contribution to consolidated net
earnings reflects a $27.0 million ($17.9 million after-tax) increase in fuel
expense, largely due to reduced gas sales margin and higher coal and oil
prices. This was only partially offset by a 5.3% rate increase that came into
effect on April 1, 2005.
"We know our 2005 earnings will be hard hit by rising fuel costs, which
are well in excess of what is currently provided for in rates," said
Chris Huskilson, President and Chief Executive Officer of Emera Inc. "High
fuel prices are a worldwide problem, and that is what is driving NSPI to
request higher rates for 2006."
Bangor Hydro, Emera's electricity transmission and distribution utility
in Maine, contributed $2.4 million to consolidated net earnings in Q2, 2005
compared to $3.5 million for the same period in 2004 due to increased
transmission and depreciation costs, and the effect of a stronger Canadian
dollar.
Other operations contributed $3.2 million to consolidated net earnings in
Q2 2005, compared to $1.3 million in Q2, 2004.
Consolidated cash provided by operating activities was $65.9 million in
Q2, 2005, compared to $92.2 million in Q2, 2004, primarily due to NSPI's
increased fuel costs.
Recent Corporate Developments
On May 24, 2005 Emera and Brascan Power Inc., in a 50-50 joint venture,
completed the acquisition of Bear Swamp, a 600 megawatt ("MW") pumped storage
hydro-electric facility in northern Massachusetts. Emera's share of the
purchase price was $61.0 million including acquisition costs. The facility
sells energy, capacity and ancillary products to the New England Power Pool.
On July 5, 2005, Nova Scotia Power filed an application with the
Nova Scotia Utility and Review Board requesting an average 15% increase in
electricity rates for 2006. Substantial increases in the price of oil, coal
and natural gas were key drivers of the application. NSPI is also proposing to
invest an additional $18.7 million towards new measures to improve customer
service, strengthen network reliability and initiate new conservation and
energy efficiency measures sought by customers. Hearings are scheduled to
begin November 14, 2005.
On July 13, 2005, Nancy Tower, FCA was appointed acting Chief Financial
Officer of Emera Inc.
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 2:00 pm Atlantic (1:00 pm
Toronto/Montreal/New York; 12:00 pm Winnipeg; 10:00 am Vancouver) to discuss
the Q2, 2005 financial results. Analysts and other interested parties wanting
to participate in the call should dial 1-800-387-6216 (in Toronto
416-405-9328) 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 3157251 (available until midnight
Wednesday, August 3, 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 July 27, 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 second quarter of 2005 relative to 2004, year to date
2005 relative to 2004, and its financial position at June 30, 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 six month period ended June 30, 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 the Bangor Hydro
section of the MD&A, which is reported in US dollars ("USD") unless otherwise
stated.
Additional information related to Emera, including the company's Annual
Information Form, can be found 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. To this end, in
Q2, 2005 Emera, in a 50-50 joint venture with Brascan Power, completed the
acquisition of Bear Swamp, a 600 megawatt ("MW") pumped storage hydro-electric
facility in Northern Massachusetts.
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, Bear Swamp and corporate activities are grouped and discussed as
"Other". Significant changes in the consolidated balance sheets, outstanding
share data, liquidity and capital resources, financial and commodity
instruments, transactions with related parties, changes in accounting
policies, and selected quarterly trend information are presented on a
consolidated basis.
<<
EMERA CONSOLIDATED
Q2 Operating Unit Contributions
(millions of dollars, except Three months ended Six months ended
earnings per common share) June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Nova Scotia Power $13.7 $25.0 $54.5 $63.8
Bangor Hydro-Electric 2.4 3.5 6.5 9.3
Other 3.2 1.3 6.6 3.2
-------------------------------------------------------------------------
Consolidated net earnings $19.3 $29.8 $67.6 $76.3
-------------------------------------------------------------------------
Earnings per common share -
basic $0.18 $0.27 $0.62 $0.70
-------------------------------------------------------------------------
Earnings per common share -
diluted $0.18 $0.27 $0.60 $0.68
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Review of Q2, 2005
Emera Inc.'s consolidated earnings decreased $10.5 million, to
$19.3 million in Q2, 2005 compared to $29.8 million for the same period in
2004. Year to date Emera's consolidated net earnings were $67.6 million in
2005 compared to $76.3 million in 2004. Highlights of the changes are
summarized in the following table:
Three Six
months months
ended ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
Consolidated net earnings - 2004 $29.8 $76.3
Increased electric revenue in NSPI due to the
5.3% rate increase effective April 1, 2005 and
increased sales volume 10.0 12.6
Increased fuel expense in NSPI due to higher
commodity prices and reduced gas sales margin (27.0) (49.5)
Decreased income taxes in NSPI as a result of
lower earnings 6.7 14.6
Deferral of Q1, 2005 taxes in NSPI as approved
by the UARB - 15.3
All other (0.2) (1.7)
-------------------------------------------------------------------------
Consolidated net earnings - 2005 $19.3 $67.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q2 earnings per share (basic) were $0.18 in 2005, compared to $0.27 in
2004; and $0.62 year to date in 2005, compared to $0.70 for the first six
months of 2004.
NOVA SCOTIA POWER INC.
Overview
Electricity Rate Increase
On March 31, 2005, the Nova Scotia Utility and Review Board granted NSPI
an average rate increase of approximately 5.3%, effective April 1, 2005. The
rate decision is expected to increase NSPI's electricity revenues by
$30-$35 million in 2005 compared to 2004.
Other key aspects of the rate decision include:
- An allowed Rate of Return on Equity of 9.55% (formerly 10.15%);
- An allowed Common Equity Component of 37.5% (formerly 35%); and
- Full recovery of $147 million Section 21 income tax deposit over
eight years, commencing in 2007.
The UARB expressed dissatisfaction with NSPI's fuel procurement practice.
The regulator disallowed $18 million of NSPI's forecasted 2005 fuel costs, and
rejected NSPI's proposal to defer an additional $13 million to 2006. As a
result, NSPI expects earnings for 2005 to be approximately $22-$27 million
lower than 2004, reflecting fuel costs that are substantially higher than what
has been provided for in rates, and the effect of the lower allowed return on
equity.
Fuel Procurement
As noted above, the UARB specified certain findings and directives
concerning NSPI's fuel procurement in its decision of March 31, 2005. On
June 20, 2005, Nova Scotia Power filed an update with the UARB outlining the
changes it has made to fuel procurement including:
- Consolidated responsibility for fuel procurement with one NSPI
person;
- Changed the fuel buying strategy team at Nova Scotia Power to remove
any potential or apparent conflicts of interest between the company
and its parent Emera;
- Strengthened the company's in-house expertise on fuel through the
judicious use of consultants;
- Engaged an executive search firm with the intention of hiring a fuel
procurement manager with international coal market and coal
procurement experience;
- Revised NSPI fuel procurement policies and procedures to more clearly
reflect a portfolio approach to procurement;
- Signed longer-term contracts for cleaner low sulphur coal -
complementing other long-term contracts already in place with other
fuel sources such as petroleum coke, local coal, transportation and
natural gas.
A final report on the actions taken by NSPI to fulfill the UARB
recommendations will be filed with the UARB by September 30, 2005.
2006 Rate Application
On July 5, 2005, Nova Scotia Power filed a general rate application
reflecting a request for an average 15% increase in electricity prices for
2006. Rising fuel prices are the key driver of the application. NSPI's fuel
expense is projected to be approximately $479 million in 2006 compared to
approximately $400 million in 2005, and the $359 million currently provided
for in rates.
The rate application also proposes an increase of $18.7 million in
operating expense to improve customer service, strengthen network reliability
and to implement new conservation and energy efficiency measures.
NSPI is seeking to maintain its allowed rate of return on common equity
of 9.55%, with a band of 25 basis points, and an associated common equity
component of 37.5%. Hearings are scheduled to commence November 14, 2005.
Review of Q2, 2005
NSPI Q2 Net Earnings
(millions of dollars, except Three months ended Six months ended
earnings per common share) June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Electric revenue $230.4 $220.4 $490.6 $478.0
-------------------------------------------------------------------------
Fuel for generation and
purchased power 91.9 64.9 196.5 147.0
Operating, maintenance and
general 46.3 44.6 92.6 89.2
Provincial grants and taxes 10.0 10.2 20.1 19.6
Provincial grants and taxes
deferral - - (4.9) -
Depreciation 29.8 29.1 59.3 58.6
Regulatory amortization 1.6 1.6 3.1 3.1
Other (2.5) (2.5) (4.5) (4.9)
-------------------------------------------------------------------------
Earnings before interest and
income taxes 53.3 72.5 128.4 165.4
Interest 24.4 25.1 49.0 50.7
Amortization of defeasance costs 3.3 3.7 6.6 7.5
-------------------------------------------------------------------------
Earnings before income taxes 25.6 43.7 72.8 107.2
Income taxes 8.6 15.3 22.1 36.7
Income taxes deferral - - (10.4) -
-------------------------------------------------------------------------
Earnings before preferred
dividends 17.0 28.4 61.1 70.5
Preferred dividends 3.3 3.4 6.6 6.7
-------------------------------------------------------------------------
Contribution to consolidated
net earnings $13.7 $25.0 $54.5 $63.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share $0.13 $0.23 $0.50 $0.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NSPI's net earnings were $13.7 million in Q2, 2005, compared to
$25.0 million in Q2, 2004. Year to date net earnings were $54.5 million in
2005 compared to $63.8 million in 2004. Highlights of the earnings changes are
summarized in the following table:
Three Six
months months
ended ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $25.0 $63.8
Increased electric revenue due to the 5.3% rate
increase effective April 1, 2005 and increased
sales volume 10.0 12.6
Increased fuel expenses due to higher commodity
prices and reduced gas sales margin (27.0) (49.5)
Increased operating expenses reflecting increased
plant maintenance and Q1 storm costs (1.7) (3.4)
Decreased income taxes resulting from lower earnings 6.7 14.6
Deferral of Q1, 2005 taxes, as approved by the UARB - 15.3
All other 0.7 1.1
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $13.7 $54.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electric Revenue
Q2 Electric Sales Volume
(GWh)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential 930 877 754
Commercial 716 693 754
Industrial 1,060 1,049 1,051
Other 81 116 152
-----------------------------------------
Total 2,787 2,735 2,711
-----------------------------------------
-----------------------------------------
Q2 Electric Sales Revenues
(millions of dollars)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential $99.0 $92.1 $74.3
Commercial 64.0 62.6 58.1
Industrial 58.7 54.8 55.2
Other 8.7 10.9 12.5
-----------------------------------------
Total $230.4 $220.4 $200.1
-----------------------------------------
-----------------------------------------
YTD Electric Sales Volume
(GWh)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential 2,218 2,184 2,041
Commercial 1,545 1,482 1,561
Industrial 2,100 2,065 1,986
Other 188 214 273
-----------------------------------------
Total 6,051 5,945 5,861
-----------------------------------------
-----------------------------------------
YTD Electric Sales Revenues
(millions of dollars)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential $222.1 $216.2 $196.8
Commercial 134.5 130.2 127.7
Industrial 115.4 111.0 106.6
Other 18.6 20.6 22.3
-----------------------------------------
Total $490.6 $478.0 $453.4
-----------------------------------------
-----------------------------------------
Q2 Average Revenue/MWh
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Dollars per MWh $83 $81 $74
---------------------------------------------------
---------------------------------------------------
YTD Average Revenue/MWh
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Dollars per MWh $81 $80 $77
---------------------------------------------------
---------------------------------------------------
Electric revenues increased $10.0 million to $230.4 million in Q2, 2005
compared to $220.4 million in Q2, 2004. This reflects volume increases and the
April 1, 2005, 5.3% rate increase approved by the UARB. Year to date electric
revenues increased $12.6 million to $490.6 million in 2005, compared to
$478.0 million in 2004.
Fuel for Generation and Purchased Power
Q2 Production Volume
(GWh)
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Coal and petcoke 2,199 2,196 2,222
Natural gas 54 10 -
Oil 253 376 314
Renewable 306 268 306
Purchased power 120 66 68
---------------------------------------------------
Total 2,932 2,916 2,910
---------------------------------------------------
---------------------------------------------------
Purchased power includes 19 GWh of wind power in 2005.
YTD Production Volume
(GWh)
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Coal and petcoke 4,682 4,728 4,678
Natural gas 95 47 21
Oil 803 979 857
Renewable 609 525 628
Purchased power 284 178 152
---------------------------------------------------
Total 6,473 6,457 6,336
---------------------------------------------------
---------------------------------------------------
Purchased power includes 39 GWh of wind power in 2005.
Q2 Average Unit Fuel Costs
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Dollars per MWh $31 $22 $24
---------------------------------------------------
---------------------------------------------------
YTD Average Unit Fuel Costs
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Dollars per MWh $30 $23 $23
---------------------------------------------------
---------------------------------------------------
For the three months ended June 30, 2005, fuel for generation and
purchased power was $91.9 million, compared to $64.9 million in Q2, 2004. Year
to date fuel for generation and purchased power was $196.5 million in 2005
compared to $147.0 million in 2004. Highlights of the changes are summarized
in the following table:
Three Six
months months
ended ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2004 $64.9 $147.0
Increased commodity pricing including change in the
fuel mix to meet environmental requirements 21.9 36.6
Increased renewable energy production volumes (3.7) (6.9)
Lower gas sales margin due to reduced volumes and
higher pricing of supply contract 3.1 17.9
All other 5.7 1.9
-------------------------------------------------------------------------
Fuel for generation and purchased power - 2005 $91.9 $196.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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, the company continues to pay for gas purchases based on the original
contract price, but is recording the expense based on management's best
estimate of the new contract price. The difference is included in Accounts
Payable and Accrued Charges and will be paid to the supplier once the
arbitration is complete. The company expects a final decision by Q4, 2005,
which may result in a price different from management's best 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.
In addition to the foregoing, the natural gas supply contract contains a
clause whereby the arbitration process has triggered a price adjustment clause
covering the next three years of natural gas purchases. NSPI will pay for all
gas purchases at an estimated future contract price, but will be entitled to a
price rebate on a portion of the volume to be settled in November 2007. Again,
management's best estimate of the price net of rebate is included in fuel for
generation and purchased power expense, with the estimated rebate recorded in
Deferred Charges and Other Receivables. There is no right of offset for these
two price adjustments.
Operating, Maintenance & General Expenses
NSPI's operating, maintenance and general expenditures ("OM&G") were
$46.3 million in Q2, 2005 compared to $44.6 million in Q2, 2004, primarily
reflecting increased plant maintenance costs and higher regulatory hearing and
consulting costs.
Year to date OM&G expenditures were $92.6 million compared to
$89.2 million for the same period in 2004. The increase reflects the items
noted above as well as higher storm costs incurred in Q1, 2005.
Provincial Grants and Taxes
Provincial grants and taxes were $10.0 million in Q2, 2005 compared to
$10.2 million in Q2, 2004. Year to date provincial grants and taxes are up
$0.5 million to $20.1 million from $19.6 million for the same period in 2004,
reflecting inflationary adjustments to provincial grants.
The UARB agreed to allow NSPI to defer taxes not reflected in rates for
the period from January 1, 2005 until April 1, 2005, the date when new rates
became effective. In Q1, 2005, NSPI deferred $4.9 million of provincial grants
and taxes to March 31, 2005. The amount of the deferral and the amortization
period are pending approval by the UARB.
Regulatory Amortization
The Glace Bay generating station has been demolished and returned to an
industrial greenfield site, and is being amortized through 2008 at a minimum
annual rate of $6.2 million. In the second quarter of 2005, $1.6 million has
been amortized (Q2, 2004 - $1.6 million). Year to date, $3.1 million has been
amortized (2004 - $3.1 million). The amount remaining to be amortized is
$15.4 million.
Interest
Interest expense decreased $0.7 million, to $24.4 million in Q2, 2005,
compared to $25.1 million in Q2, 2004, due to the refinancing in May 2005 of a
$100 million 8.38% mid-term note with a $100 million 4.22% mid-term note. Year
to date interest expense decreased $1.7 million to $49.0 million from
$50.7 million for the same period in 2004 due to the above and the refinancing
of a $140 million mid-term note with short-term debt in Q1, 2004.
Income Taxes
The UARB agreed to allow NSPI to defer taxes not reflected in rates for
the period from January 1, 2005 until April 1, 2005, the date when new rates
became effective. In Q1, 2005, NSPI deferred $10.4 million of federal capital
taxes and income taxes reflecting increases in these taxes since rates were
last set in 2002. The amount of the deferral and the amortization period are
pending approval by the UARB.
NSPI has a $147 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 approved the amortization and recovery of this regulatory asset
over eight years, commencing in 2007.
Debt Management
On May 17, 2005, NSPI issued $100 million medium-term notes at a coupon
rate of 4.22% maturing May 17, 2010. The proceeds were used to refinance
$100 million 8.38% medium-term notes that matured on that date. In February
2004, a $140 million 7.3% mid-term note matured and was refinanced with
short-term debt.
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 Q2, 2005
Bangor Hydro Q2 Net Earnings
(millions of dollars, except Three months ended Six months ended
earnings per common share) June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
T&D revenues $24.0 $26.6 $53.3 $57.8
Resale of purchased power 3.9 2.2 6.2 6.6
-------------------------------------------------------------------------
Total electric revenue 27.9 28.8 59.5 64.4
Purchased power and fuel for
generation 8.6 7.7 16.6 19.2
Operating, maintenance and
general 8.3 7.9 16.3 15.4
Property taxes 1.3 1.2 2.7 2.5
Depreciation 3.1 2.5 6.2 5.2
Regulatory amortization 2.3 3.3 6.2 6.3
Other (1.1) (0.8) (2.0) (1.4)
-------------------------------------------------------------------------
Earnings before interest and
income taxes 5.4 7.0 13.5 17.2
Interest 2.5 2.6 5.0 5.4
-------------------------------------------------------------------------
Earnings before income taxes 2.9 4.4 8.5 11.8
Income taxes 1.0 1.8 3.2 4.8
-------------------------------------------------------------------------
Contribution to consolidated
net earnings - US $ $1.9 $2.6 $5.3 $7.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
net earnings - Canadian $ $2.4 $3.5 $6.5 $9.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share -
Canadian $ $0.02 $0.03 $0.06 $0.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings weighted average
foreign exchange rate
Canadian/US $ $1.2450 $1.3603 $1.2326 $1.3298
Bangor Hydro's contribution to consolidated net earnings was $1.9 million
in Q2, 2005, compared to $2.6 million in Q2, 2004. Year to date, Bangor
Hydro's contribution to consolidated net earnings was $5.3 million, compared
to $7.0 million in 2004. Highlights of the earnings changes are summarized in
the following table:
Three Six
months months
ended ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $2.6 $7.0
Write-off in Q2, 2004 of deferred costs disallowed
in rates 1.1 1.1
Increased NEPOOL related transmission expenses (0.7) (1.1)
Increased depreciation expense due to depreciation
study impacts (0.6) (1.0)
Reduced overhead allocation to capital program (0.4) (0.7)
All other (0.1) -
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $1.9 $5.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bangor Hydro's contribution to consolidated net earnings was $2.4 million
CAD in Q2, 2005 compared to $3.5 million CAD in Q2, 2004, due to the Canadian
dollar equivalent of the variances discussed above and the $0.2 million impact
of the stronger Canadian dollar. Year to date net earnings contributed by
Bangor Hydro was $6.5 million for 2005 compared to $9.3 million for 2004, due
to the Canadian dollar equivalent of the variances discussed above and the
$0.5 million impact of the stronger Canadian dollar.
Electric Revenue
Q2 T&D Sales Volume
(GWh)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential 141 135 136
Commercial 146 142 144
Industrial 96 76 77
Other 3 3 3
-----------------------------------------
Total 386 356 360
-----------------------------------------
-----------------------------------------
Q2 T&D Sales Revenues
(millions of US dollars)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential $11.7 $13.0 $12.8
Commercial 8.8 9.9 9.8
Industrial 2.1 3.1 3.4
Other 1.4 0.6 1.6
-----------------------------------------
Total $24.0 $26.6 $27.6
-----------------------------------------
-----------------------------------------
YTD T&D Sales Volume
(GWh)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential 300 300 298
Commercial 296 297 295
Industrial 195 147 172
Other 6 6 6
-----------------------------------------
Total 797 750 771
-----------------------------------------
-----------------------------------------
YTD T&D Sales Revenues
(millions of US dollars)
-----------------------------------------
2005 2004 2003
-----------------------------------------
Residential $25.9 $28.1 $26.9
Commercial 18.8 20.8 20.6
Industrial 6.0 6.9 7.7
Other 2.6 2.0 3.3
-----------------------------------------
Total $53.3 $57.8 $58.5
-----------------------------------------
-----------------------------------------
Q2 Average Revenue/MWh
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Dollars per MWh $62 $75 $77
---------------------------------------------------
---------------------------------------------------
YTD Average Revenue/MWh
---------------------------------------------------
2005 2004 2003
---------------------------------------------------
Dollars per MWh $67 $77 $76
---------------------------------------------------
---------------------------------------------------
BHE's electric revenues decreased by $2.6 million in Q2, 2005, to
$24.0 million compared to $26.6 million in Q2, 2004. Year to date, Bangor
Hydro's T&D electric revenues were $53.3 million compared to $57.8 million for
the same period. Highlights of the changes are summarized in the following
table:
Three Six
months months
ended ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
T&D revenues - 2004 $26.6 $57.8
Stranded cost rate reduction on March 1, 2005 (4.0) (5.5)
Increased residential and small commercial energy sales 0.7 -
All other 0.7 1.0
-------------------------------------------------------------------------
T&D revenues - 2005 $24.0 $53.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Increases to industrial volumes had a minimal impact on sales revenues
due to lower unit pricing.
Outlook
On February 25, 2005, the Maine Public Utilities Commission approved
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 approximate 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.
In accordance with the provisions of BHE's Alternate Rate Plan ("ARP"),
BHE's distribution rates decreased by approximately 2.4% on July 1, 2005. BHE
anticipates managing the reduction to revenue with sales volume growth and
ongoing management of its operating, maintenance and general expenditures.
Operating, Maintenance and General Expenditures
Operating expenses were $0.4 million higher in Q2, 2005 at $8.3 million
compared to $7.9 million in Q2, 2004 primarily due to lower capital
allocations.
Year to date operating expenses were $0.9 million higher at $16.3 million
compared to $15.4 million for 2004 for the reason noted above.
Regulatory Amortization
Amortization expense was $1.0 million lower in Q2, 2005 at $2.3 million,
compared to $3.3 million in Q2, 2004 reflecting the new amortizations starting
March 1, 2005 in connection with new stranded cost rates. Year to date
amortization expense was $6.2 million in 2005, compared to $6.3 million in
2004. New amortizations in connection with the new stranded cost rates were
offset by the completion of amortization on certain regulatory liabilities in
Q1, 2004.
Interest
BHE's interest expense decreased slightly to $2.5 million in Q2, 2005
from $2.6 million in Q2, 2004 due principally to long-term debt repayments in
the latter part of 2004. This also accounts for the decrease to $5.0 million
year to date, 2005, compared to $5.4 million in 2004.
OTHER
All activities of Emera other than its two regulated electric utilities
are incorporated in Other, including:
- Emera Energy Services, which manages energy assets on behalf of third
parties and provides related energy management services. Emera Energy
Services operates with minimal day-to-day commodity risk exposure.
- A 12.9% interest in the $2 billion, 1,300 kilometre Maritimes &
Northeast Pipeline ("M&NP") that transports Nova Scotia's offshore
natural gas to markets in Maritime Canada and the northeastern United
States.
- 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.
- Bear Swamp, a 50-50 joint venture in a 600 megawatt pumped storage
hydro-electric facility in northern Massachusetts.
- 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.
Acquisition
On May 24, 2005 Emera and Brascan Power Inc., in a 50-50 joint venture,
completed the acquisition of Bear Swamp, a 600 megawatt ("MW") pumped storage
hydro-electric facility in northern Massachusetts. Emera's share of the
purchase price was $61.0 million including acquisition costs. The facility
sells energy, capacity and ancillary products to the New England Power Pool.
Also included in the acquisition is the nearby 10 MW Fife Brook run-of-river
hydro facility.
The acquisition has been accounted for under the purchase method of
accounting, and accordingly, the results of operations since the date of
acquisition have been included in the consolidated statement of earnings and
the summary statement of earnings below. Bear Swamp contributed $0.3 million
to net earnings in Q2, 2005.
Review of Q2, 2005
Other Q2 Net Earnings
(millions of dollars, except Three months ended Six months ended
earnings per common share) June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Fuel oil sales $21.4 $18.4 $50.6 $47.5
M&NP equity earnings 1.5 1.5 3.3 3.6
Energy marketing margin 3.8 3.7 11.1 13.6
Electric revenue 1.9 - 1.9 -
-------------------------------------------------------------------------
28.6 23.6 66.9 64.7
-------------------------------------------------------------------------
Cost of fuel oil sold 18.8 16.0 43.5 40.1
Operating, maintenance and
general 7.1 7.4 14.8 15.3
Business development 0.7 0.8 0.5 3.9
Depreciation 0.7 0.3 1.3 1.0
Other (1.1) (1.9) (2.1) (2.8)
-------------------------------------------------------------------------
Earnings before interest and
income taxes 2.4 1.0 8.9 7.2
Interest (1.3) 2.9 1.3 7.0
-------------------------------------------------------------------------
Earnings before income taxes 3.7 (1.9) 7.6 0.2
Income taxes 0.5 (3.2) 1.0 (3.0)
-------------------------------------------------------------------------
Contribution to consolidated
net earnings $3.2 $1.3 $6.6 $3.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contribution to consolidated
earnings per common share $0.03 $0.01 $0.06 $0.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The contribution of Other operations to consolidated net earnings
increased $1.9 million quarter over quarter and increased $3.4 million year to
date 2005 compared to 2004. Highlights of the quarter over quarter changes are
summarized in the following table:
Three Six
months months
ended ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2004 $1.3 $3.2
Lower interest expense primarily due to foreign
exchange gains 4.2 5.7
Higher income taxes due to higher earnings (3.7) (4.0)
Write-off of Greyhawk Gas Storage joint venture in
Q1, 2004 - 1.9
All other 1.4 (0.2)
-------------------------------------------------------------------------
Contribution to consolidated net earnings - 2005 $3.2 $6.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Equity Earnings
Equity earnings from the Maritimes & Northeast Pipeline were $1.5 million
in Q2, 2005, unchanged from the same period in 2004. Increases in the tolls
collected for the US operations have been offset by the write off of
previously deferred costs for pipeline expansion on the US pipeline, and the
impact of the stronger Canadian dollar on the US portion of the pipeline. Year
to date equity earnings were $3.3 million in 2005 compared to $3.6 million in
2004 for the same reasons.
In 2004 Maritimes & Northeast Pipeline filed a Notice of Rate Increase
for its US operations. The changes reflected in the filing result principally
from:
- A decline in reserves and deliverability associated with the Sable
Offshore Energy Project fields;
- The inclusion in the rates of costs related to the Phase III
expansion project M&NP placed into service on November 24, 2003; and
- An updated cost of service.
Effective January 1, 2005 M&NP was permitted to collect proposed rates
from customers, pending approval of new rates. Any cash collected in excess of
the new rates, once approved, will be returned to customers.
On June 28, 2005 M&NP submitted an offer of settlement to the Federal
Energy Regulatory Commission. In Q2, 2005 the company recognized its best
estimate of $1.0 million (year to date - $3.0 million) in equity earnings and
energy marketing margin, which represents revenue recognized in excess of
existing approved rates, and is based on the terms of the proposed settlement.
Energy Marketing Margin
Emera Energy Services net margin was consistent quarter over quarter at
$3.8 million in Q2, 2005, compared to $3.7 million in Q2, 2004. Year to date
net margin was $11.1 million compared to $13.6 million as a result of
decreased margin on natural gas marketing opportunities.
Electric Revenue
Electric revenue represents Emera's share of electric revenue from Bear
Swamp since the date of acquisition on May 24, 2005.
Business Development
Business development costs were $0.7 million in Q2, 2005, compared to
$0.8 million in Q2, 2004.
Year to date business development costs were $0.5 million compared to
$3.9 million for the same period in 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 Q1, 2005; the business
development expenses capitalized as part of the Bear Swamp acquisition; and
the deferral of business development expenses related to the pending
acquisition of another hydro generation facility.
Interest
Interest expense was $(1.3) million in Q2, 2005 compared to $2.9 million
in Q2, 2004 largely as a result of the translation impact of a stronger
Canadian dollar on the company's US dollar denominated financial obligations,
and a favorable adjustment required to refine prior years' foreign exchange
recognized on US denominated obligations. Year to date interest was
$1.3 million in 2005 compared to $7.0 million in 2004 due to the same reasons.
Consolidated Balance Sheets
Significant changes in the consolidated balance sheets between June 30,
2005 and December 31, 2004 include:
- $17.4 million decrease in restricted cash, reflecting a reduction in
the number of counterparties required to post margin as a deposit.
- $20.7 million increase in accounts receivable, reflecting the
increase in rates and a decrease in the amount of accounts receivable
securitized in NSPI, and increased volumes and price in Emera Energy
Services.
- $15.7 million increase in income tax receivable, reflecting payments
related to 2004 and 2005 income taxes in NSPI and future income taxes
in Emera Energy Services that have become a current receivable in
2005.
- $17.9 million increase in inventory reflecting an increase in coal
inventory levels and higher commodity prices.
- $21.0 million increase in prepaid expenses, reflecting the timing of
the payment of the provincial grants in lieu.
- $62.4 million increase in capital assets, reflecting the acquisition
of the hydro-electric facility in northern Massachusetts.
- $18.7 million increase in accounts payable and accrued charges,
reflecting the increase in fuel related payables due to the
arbitration of a supply contract somewhat offset by the timing of
payments.
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 0.21 3.8
Options exercised under senior management share
option plan 0.56 9.0
Share-based compensation - 0.5
-------------------------------------------------------------------------
June 30, 2005 109.64 $1,032.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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.
In July 2005 NSPI's Board of Directors approved an increase to the size
of its commercial paper program from $350 million to $400 million. The
company's banking syndicate provides 100% backup facility for this program.
On July 5, 2005, Standard & Poor's Rating Services revised its outlook
for Emera and Nova Scotia Power to negative from stable citing fuel cost
recovery concerns. On July 6, 2005 the Dominion Bond Rating Service ("DBRS")
confirmed Emera's and NSPI's ratings as BBB (high) and A (low) respectively.
NSPI's commercial paper rating was confirmed at R-1 (Low).
Consolidated Cash Flow Highlights
Three months ended Six months ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Net cash provided by operating
activities $65.9 $92.2 $83.9 $147.9
Net cash provided by (used in)
financing activities 19.0 (55.1) (1.9) (89.6)
Net cash used in investing
activities (82.4) (39.1) (92.0) (50.3)
-------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents $2.5 $(2.0) $(10.0) $8.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated net cash provided by operating activities was $65.9 million
in Q2, 2005, compared to $92.2 million in Q2, 2004 reflecting increased fuel
costs in NSPI and working capital changes. Year to date consolidated net cash
provided by operating activities was $83.9 million in 2005 compared to
$147.9 million in 2004 for these same reasons.
Consolidated net cash provided by financing activities increased
$74.1 million in Q2, 2005, compared to Q2, 2004, and increased $87.7 million
year to date 2005 compared to 2004, reflecting higher consolidated debt levels
in order to fund the acquisition of Bear Swamp and higher fuel costs in NSPI.
Consolidated net cash used in investing activities increased
$43.3 million in the quarter over prior year and $41.7 million year to date
over prior year, due primarily to the acquisition of the Bear Swamp
hydro-electric facility.
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)
-------------------------------------------------------------------------
June 30 December 31
2005 2004
-------------------------------------------------------------------------
Inventory $1.0 $1.6
Deferred charges - 0.1
Accounts payable and accrued charges (0.1) (0.3)
-------------------------------------------------------------------------
Deferred hedging losses $0.9 $1.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three month and six month periods ended June 30, the impacts of
effective hedges recognized in earnings were recorded in the following
categories:
Hedging Impact Recognized
in Earnings Three months ended Six months ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Fuel and purchased power decrease
(increase) $(4.2) $0.9 $(8.0) $(4.8)
Interest expense increase (0.5) (1.1) (0.9) (2.9)
-------------------------------------------------------------------------
Hedging earnings impact $(4.7) $(0.2) $(8.9) $(7.7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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)
-----------------------------------------------------
June 30 December 31
2005 2004
-----------------------------------------------------
Energy marketing assets $8.3 $10.3
Energy marketing liabilities (6.1) (9.4)
-----------------------------------------------------
Mark-to-market gains $2.2 $0.9
-----------------------------------------------------
-----------------------------------------------------
Mark-to-Market Gains (Losses)
Recognized in Earnings Three months ended Six months ended
(millions of dollars) June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Other revenue $1.9 $(0.1) $1.3 $0.2
Fuel and purchased power - 4.3 - (1.3)
-------------------------------------------------------------------------
Mark-to-market gains (losses) $1.9 $4.2 $1.3 $(1.1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
In the ordinary course of business, Emera purchased transportation
capacity totaling $10.4 million (2004 - $11.8 million) during the three months
ended June 30, 2005, and $20.2 million (2004 - $23.8 million) during the six
months ended June 30, 2005, 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 June 30, 2005 the
amount payable to the related party is $3.4 million (December 31, 2004 -
$3.2 million), is non-interest 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)
-------------------------------------------------------------------------
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
2005 2005 2004 2004 2004 2004 2003 2003
-------------------------------------------------------------------------
Total revenues $296.9 $338.9 $309.4 $276.0 $287.2 $347.4 $310.3 $281.0
Net earnings
applicable to
common shares $19.3 $48.3 $31.4 $22.1 $29.8 $46.5 $47.5 $11.5
Earnings per
common share
- basic $0.18 $0.44 $0.30 $0.20 $0.27 $0.43 $0.44 $0.11
Earnings per
common share
- diluted $0.18 $0.42 $0.28 $0.20 $0.27 $0.41 $0.43 $0.11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
(millions of dollars, except earnings per common share)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Revenue
Electric $267.0 $261.0 $566.0 $566.8
Fuel oil 21.4 18.4 50.6 47.0
Other (note 14) 8.5 7.8 19.2 20.8
-------------------------------------------------------------------------
296.9 287.2 635.8 634.6
-------------------------------------------------------------------------
Cost of operations
Fuel for generation and
purchased power
(notes 10 and 14) 102.6 76.3 217.0 174.1
Cost of fuel oil sold 18.8 16.0 43.5 39.7
Operating, maintenance, and
general 64.4 63.6 128.0 129.1
Provincial, state, and
municipal taxes 12.4 11.7 24.4 23.1
Provincial tax deferral
(note 9) - - (4.9) -
Depreciation 34.3 32.7 68.3 66.5
-------------------------------------------------------------------------
232.5 200.3 476.3 432.5
-------------------------------------------------------------------------
Earnings from operations 64.4 86.9 159.5 202.1
Equity earnings (note 7 and 15) 1.5 1.5 3.3 3.6
Regulatory amortization (4.6) (6.1) (10.8) (11.6)
Allowance for funds used
during construction 1.2 0.7 2.0 1.4
-------------------------------------------------------------------------
Earnings before interest and
income taxes 62.5 83.0 154.0 195.5
Interest (note 8) 26.1 31.6 56.4 65.0
Amortization of defeasance costs 3.3 3.7 6.6 7.5
-------------------------------------------------------------------------
Earnings before income taxes 33.1 47.7 91.0 123.0
Income taxes 10.4 14.5 27.1 40.0
Income taxes deferral (note 9) - - (10.4) -
-------------------------------------------------------------------------
Net earnings before
non-controlling interest 22.7 33.2 74.3 83.0
Non-controlling interest
(note 13) 3.4 3.4 6.7 6.7
-------------------------------------------------------------------------
Net earnings applicable to
common shares $19.3 $29.8 $67.6 $76.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share -
basic $0.18 $0.27 $0.62 $0.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share -
diluted $0.18 $0.27 $0.60 $0.68
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Weighted average number of
common shares outstanding
(millions) - basic 109.4 108.4 109.2 108.4
- diluted 109.4 108.4 123.1 122.7
Consolidated Statements of Retained Earnings (Unaudited)
For the six months ended June 30
(millions of dollars)
-------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------
Retained earnings, beginning of year $399.6 $365.3
Net earnings applicable to common shares 67.6 76.3
-------------------------------------------------------------------------
467.2 441.6
Dividends 48.5 47.7
-------------------------------------------------------------------------
Retained earnings, end of period $418.7 $393.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Consolidated Balance Sheets (Unaudited)
As at
(millions of dollars)
-------------------------------------------------------------------------
June 30 December 31
2005 2004
-------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $32.7 $42.7
Restricted cash 0.8 18.2
Accounts receivable 196.8 176.1
Income tax receivable 18.1 2.4
Inventory 91.3 73.4
Prepaid expenses 26.4 5.4
Future income tax assets 3.8 3.6
Energy marketing assets 8.3 10.3
-------------------------------------------------------------------------
378.2 332.1
-------------------------------------------------------------------------
Long-term receivable 20.0 20.0
-------------------------------------------------------------------------
Deferred charges and other receivables (note 10) 584.7 580.2
-------------------------------------------------------------------------
Future income tax assets 26.8 34.1
-------------------------------------------------------------------------
Goodwill 109.5 107.7
-------------------------------------------------------------------------
Investments (note 11) 100.7 96.8
-------------------------------------------------------------------------
Property, plant and equipment 2,761.3 2,714.6
Construction work in progress 79.4 63.7
-------------------------------------------------------------------------
2,840.7 2,778.3
-------------------------------------------------------------------------
$4,060.6 $3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Current portion of long-term debt $150.0 $100.8
Short-term debt 332.6 145.4
Accounts payable and accrued charges 252.1 233.4
Income tax payable 0.5 1.4
Dividends payable 3.2 3.2
Energy marketing liabilities 6.1 9.4
-------------------------------------------------------------------------
744.5 493.6
-------------------------------------------------------------------------
Future income tax liabilities 83.7 82.2
-------------------------------------------------------------------------
Asset retirement obligations 70.3 68.5
-------------------------------------------------------------------------
Deferred credits 82.9 80.8
-------------------------------------------------------------------------
Long-term debt (note 12) 1,448.4 1,626.5
-------------------------------------------------------------------------
Non-controlling interest 260.8 260.8
-------------------------------------------------------------------------
Shareholders' equity
Common shares 1,032.5 1,019.2
Foreign exchange translation adjustment (81.2) (82.0)
Retained earnings 418.7 399.6
-------------------------------------------------------------------------
1,370.0 1,336.8
-------------------------------------------------------------------------
$4,060.6 $3,949.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contingencies (Note 15)
See accompanying notes to the unaudited consolidated financial
statements.
Approved on behalf of the Board of Directors
Derek Oland Christopher Huskilson
Chairman President and Chief Executive Officer
Consolidated Statements of Cash Flow (Unaudited)
For the
(millions of dollars)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
Operating activities
Net earnings before
non-controlling interest $22.7 $33.2 $74.3 $83.0
Non-cash items:
Depreciation 34.3 32.7 68.3 66.5
Deferral of provincial taxes
and income taxes - - (15.3) -
Amortization of deferred charges 7.0 3.3 14.7 19.2
Equity earnings (1.5) (1.5) (3.3) (3.6)
Regulatory amortization 4.6 6.1 10.8 11.6
Allowance for funds used during
construction (1.2) (0.7) (2.0) (1.4)
Future income taxes 6.9 (1.9) 7.1 (7.3)
Other cash operating items (1.5) 4.6 (8.3) 2.3
-------------------------------------------------------------------------
71.3 75.8 146.3 170.3
Change in non-cash operating
working capital (5.4) 16.4 (62.4) (22.4)
-------------------------------------------------------------------------
Net cash provided by operating
activities 65.9 92.2 83.9 147.9
-------------------------------------------------------------------------
Financing activities
Retirements of long-term debt (101.1) (23.1) (102.3) (164.1)
Issuance of long-term debt 100.0 - 100.0 -
Increase (decrease) in
short-term debt 42.5 (5.9) 56.6 126.2
Issuance of common shares 8.8 2.3 12.9 4.4
Dividends on common shares (24.4) (23.9) (48.5) (47.7)
Dividends paid by subsidiaries
to non-controlling interest (3.4) (3.7) (6.7) (7.1)
Accounts receivable
securitization - - (10.0) -
Other financing (3.4) (0.8) (3.9) (1.3)
-------------------------------------------------------------------------
Net cash provided by (used in)
financing activities 19.0 (55.1) (1.9) (89.6)
-------------------------------------------------------------------------
Investing activities
Property, plant and equipment (33.9) (31.9) (53.6) (46.5)
Acquisitions (note 4) (52.6) - (52.6) -
Retirement spending net of
salvage (1.0) (0.4) (1.7) (1.0)
Proceeds from sale of assets - 0.8 - 0.8
Decrease (increase) in
restricted cash 5.1 (7.3) 17.4 (2.5)
Other investing activities - (0.3) (1.5) (1.1)
-------------------------------------------------------------------------
Net cash used in investing
activities (82.4) (39.1) (92.0) (50.3)
-------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 2.5 (2.0) (10.0) 8.0
Cash and cash equivalents,
beginning of period 30.2 20.0 42.7 10.0
-------------------------------------------------------------------------
Cash and cash equivalents, end
of period $32.7 $18.0 $32.7 $18.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash and cash equivalents
consists of:
Cash $27.1 $14.9 $27.1 $14.9
Cash equivalents 5.6 3.1 5.6 3.1
-------------------------------------------------------------------------
Cash and cash equivalents, end
of period $32.7 $18.0 $32.7 $18.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental disclosure of cash
paid:
Interest $31.5 $30.6 $61.1 $67.2
Income and capital taxes $21.0 $23.1 $33.1 $46.9
-------------------------------------------------------------------------
See accompanying notes to the unaudited consolidated financial
statements.
Notes to the Interim Unaudited
Consolidated Financial Statements
June 30, 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 its current
evaluation of these agreements.
4. Acquisitions
On May 24, 2005 Emera and Brascan Power Inc., in a 50-50 joint
venture, acquired Bear Swamp, a 600 megawatt ("MW") pumped storage
hydro-electric facility in northern Massachusetts. Emera's share of
the purchase price was $61.0 million. The facility sells energy,
capacity and ancillary products to the New England Power Pool. Also
included in the acquisition is the nearby 10 MW Fife Brook
run-of-river hydro facility.
The acquisition has been accounted for under the purchase method of
accounting, and accordingly, the results of operations since the date
of acquisition have been included in the consolidated statement of
earnings.
Emera's share of the transaction is summarized as follows:
Net Assets Acquired (millions of dollars)
---------------------------------------------------------------------
Property, plant and equipment $60.7
Construction work in progress 0.3
---------------------------------------------------------------------
$61.0
---------------------------------------------------------------------
---------------------------------------------------------------------
5. Segment Information
Segmented financial information for the three months ended and as at
June 30, 2005:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $232.3 $35.6 $29.0 $296.9
Depreciation 29.8 3.8 0.7 34.3
Cost of operations, including
depreciation 178.0 26.5 28.0 232.5
Net intersegment operating
revenues/(expenses) 32.6 (0.6) (32.0) -
Equity earnings - - 1.5 1.5
Interest expense 24.4 3.0 (1.3) 26.1
Income taxes 8.6 1.3 0.5 10.4
Net earnings applicable to
common shares 13.7 2.4 3.2 19.3
Segment assets 3,048.8 609.5 402.3 4,060.6
Segment goodwill - 101.2 8.3 109.5
Capital expenditures 28.8 6.5 51.2 86.5
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented financial information for the three months ended and as at
June 30, 2004:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $222.1 $40.2 $24.9 $287.2
Depreciation 29.1 3.3 0.3 32.7
Cost of operations, including
depreciation 148.8 26.2 25.3 200.3
Net intersegment operating
revenues/(expenses) 41.7 (0.2) (41.5) -
Equity earnings - - 1.5 1.5
Interest expense 25.1 3.6 2.9 31.6
Income taxes 15.3 2.4 (3.2) 14.5
Net earnings applicable to
common shares 25.0 3.5 1.3 29.8
Segment assets 2,991.1 674.3 276.1 3,941.5
Segment goodwill - 110.6 8.4 119.0
Capital expenditures 47.7 6.4 (22.2) 31.9
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented financial information for the six months ended and as at
June 30, 2005:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $494.0 $75.0 $66.8 $635.8
Depreciation 59.3 7.7 1.3 68.3
Cost of operations, including
depreciation 363.6 51.7 61.0 476.3
Net intersegment operating
revenues/(expenses) 65.1 (1.3) (63.8) -
Equity earnings - - 3.3 3.3
Interest expense 49.0 6.1 1.3 56.4
Income taxes 22.1 4.0 1.0 27.1
Net earnings applicable to
common shares 54.5 6.5 6.6 67.6
Segment assets 3,048.8 609.5 402.3 4,060.6
Segment goodwill - 101.2 8.3 109.5
Capital expenditures 40.0 15.0 51.2 106.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented financial information for the six months ended and as at
June 30, 2004:
(millions of dollars)
---------------------------------------------------------------------
NSPI Bangor Other(x) Total
Hydro
---------------------------------------------------------------------
Revenues from external
customers $481.4 $87.9 $65.3 $634.6
Depreciation 58.6 6.9 1.0 66.5
Cost of operations, including
depreciation 314.4 56.6 61.5 432.5
Net intersegment operating
revenues/(expenses) 87.4 (0.8) (86.6) -
Equity earnings - - 3.6 3.6
Interest expense 50.7 7.3 7.0 65.0
Income taxes 36.7 6.3 (3.0) 40.0
Net earnings applicable to
common shares 63.8 9.3 3.2 76.3
Segment assets 2,991.1 674.3 276.1 3,941.5
Segment goodwill - 110.6 8.4 119.0
Capital expenditures 58.0 10.1 (21.6) 46.5
---------------------------------------------------------------------
(x) Other consists of items related to corporate activities and other
subsidiaries.
6. 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 June 30, 2005 is $7.3 million (2004 - $6.9 million), and for
the six month period ended June 30, 2005 is $14.6 million (2004 -
$13.8 million).
7. Equity Earnings
Equity earnings of $1.5 million (2004 - $1.5 million) for the three
months ended June 30, 2005, and $3.3 million (2004 - $3.6 million)
for the six months ended June 30, 2005, 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.
8. Interest
Interest expense consists of the following:
Three months ended Six months ended
June 30 June 30
---------------------------------------------------------------------
(millions of dollars) 2005 2004 2005 2004
---------------------------------------------------------------------
Interest on long-term debt $26.4 $27.7 $53.2 $56.9
Interest on short-term debt 4.4 3.1 7.7 6.4
Amortization of debt financing 0.7 0.6 1.0 0.8
Foreign exchange losses (gains) (5.4) 0.2 (5.5) 0.9
---------------------------------------------------------------------
$26.1 $31.6 $56.4 $65.0
---------------------------------------------------------------------
---------------------------------------------------------------------
9. Provincial Tax Deferral and Income Tax Deferral
The UARB agreed to allow NSPI to defer taxes not reflected in rates
for the period January 1, 2005 until April 1, 2005, the date when new
rates became effective. In Q1, 2005, NSPI deferred $15.3 million of
provincial and federal grants and taxes. The amount of the deferral
and the amortization period are pending approval by the UARB.
10. Deferred Charges and Other Receivables
Deferred Charges
NSPI has a $147 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 approved the
amortization and recovery of this regulatory asset over eight years,
commencing in 2007.
Other Receivables
The natural gas supply contract contains a clause whereby the
arbitration process has triggered a price adjustment clause covering
the next three years of natural gas purchases. NSPI will pay for all
gas purchases at an estimated future contract price, but will be
entitled to a price rebate on a portion of the volume to be settled
in November 2007. Management's best estimate of the price net of
rebate is included in fuel for generation and purchased power
expense, with the estimated rebate recorded in Deferred Charges and
Other Receivables.
11. Investments
Investments are comprised of the following:
June 30 December 31
(millions of dollars) 2005 2004
---------------------------------------------------------------------
Equity accounted investments
Maritimes & Northeast Pipeline $92.4 $88.0
Maine Yankee Atomic Power Company 2.1 3.1
Maine Electric Power Company Inc. 1.2 1.4
Intragas Energy 1.9 1.9
---------------------------------------------------------------------
Total equity investments 97.6 94.4
Long-term portfolio investments 3.1 2.4
---------------------------------------------------------------------
$100.7 $96.8
---------------------------------------------------------------------
---------------------------------------------------------------------
12. 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.
13. Common Shares and Non-Controlling Interest
As of June 30, 2005 there were 109,643,968 (December 31, 2004 -
108,865,616) issued and outstanding common shares, 520,284
(December 31, 2004 - 1,083,759) common shares reserved for issuance
under the senior management common share option plan, and 1,331,405
(December 31, 2004 - 1,403,376) common shares reserved for issuance
under the employee common share purchase plan.
During the six months ended June 30, 2005, the Company issued 778,352
(2004 - 266,591) common shares for cash proceeds of $12.9 million
(2004 - $4.4 million). Additionally, $0.5 million (2004 -
$0.5 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 June 30, 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 June 30, 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.
14. Related Party Transactions
In the ordinary course of business, the Company purchased
transportation capacity totaling $10.4 million (2004 - $11.8 million)
for the three months ended June 30, 2005, and $20.2 million (2004 -
$23.8 million) for the six months ended June 30, 2005, from the
Maritimes & Northeast Pipeline, an investment under significant
influence of the Company. The amount is recognized in fuel for
generation and purchased power or netted against energy marketing
margin in other revenue, and is measured at the exchange amount. As
at June 30, 2005 the amount payable to the related party is
$3.4 million (December 31, 2004 - $3.2 million), and is non-interest
bearing and is under normal credit terms.
15. Contingencies
Effective January 1, 2005 M&NP was permitted to collect proposed
rates from customers, pending regulatory approval of new rates. Any
cash collected in excess of the new rates, once approved, will be
returned to customers. On June 28, 2005 M&NP submitted an offer of
settlement to the Federal Energy Regulatory Commission. The Company
recognized its best estimate of $1.0 million for the three months
ended June 30, 2005, and $3.0 million for the six months ended
June 30, 2005, in equity earnings and energy marketing margin, which
represents revenue recognized in excess of existing approved rates,
and is based on the terms of the proposed settlement.
As part of an ongoing litigation against a coal supplier, NSPI was
required to post a bond. The bond may be called if NSPI does not
prosecute the claim without delay, or if the claim is not successful.
It is not determinable whether NSPI will be successful with its
claim, accordingly, an estimate of the potential contingent loss
cannot be made.
16. 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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