Fortis Earns $285 Million in 2010 Delivers Record Earnings for 11th Consecutive Year

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved net earnings attributable to common equity shareholders of $285 million, or $1.65 per common share, up $23 million from earnings of $262 million, or $1.54 per common share, in 2009. 

Performance for the year was driven by Canadian Regulated Utilities and non-regulated hydroelectric generation operations. Tempering results year over year were lower earnings from Caribbean Regulated Electric Utilities and higher corporate expenses. 

Fortis has raised its annualized dividend to common shareholders for 38 consecutive years, the record for a public corporation in Canada. Dividends paid per common share were $1.12 in 2010, up 7.7% from $1.04 paid per common share in the previous year. The dividend payout ratio was approximately 68% in 2010. Fortis increased its quarterly common share dividend to 29 cents from 28 cents, commencing with the first quarter dividend payable on March 1, 2011, which translates into an annualized dividend of $1.16.

"For the second consecutive year our capital program surpassed $1 billion, reaching a record approximate $1.1 billion in 2010," says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "The US$53 million 19-megawatt hydroelectric generating facility at Vaca in Belize was commissioned last March and completes the three-phase hydroelectric development for the Macal River. Several significant capital projects continued throughout 2010 and are slated for completion in the coming months. FortisAlberta will substantially complete its approximate $126 million multi-year Automated Meter Infrastructure Project, which involves the replacement of some 466,000 conventional meters, by the end of March 2011. FortisBC is on track to complete its $106 million Okanagan Transmission Reinforcement Project, the largest capital project ever undertaken by the utility, by mid-2011. At Terasen Gas (Vancouver Island), construction of the $210 million liquefied natural gas storage facility is expected to be completed during the second quarter of 2011, with the facility coming into service by late 2011. A little further out on the horizon, in early 2012, the $110 million Customer Care Enhancement Project, currently underway at Terasen Gas, is scheduled for completion," he explains.

In October 2010 Fortis, in partnership with Columbia Power Corporation and Columbia Basin Trust, concluded definitive agreements to construct the $900 million 335-megawatt ("MW") Waneta Expansion hydroelectric generating facility on the Pend d'Oreille River in British Columbia. Fortis owns a 51% controlling interest in the non-regulated partnership, which has negotiated 40-year power sales agreements with BC Hydro and FortisBC for the energy and capacity, respectively, to be generated by the facility. Last fall, construction began on the Waneta Expansion. Fortis will operate and maintain the facility when it comes into service, which is expected in spring 2015. "British Columbia and the Pacific Northwest region provide potential to pursue hydroelectric generation assets that complement the utility operations of Fortis in western Canada and deliver value to our customers and shareholders," says Marshall. 

The Terasen Gas companies delivered earnings of $130 million, up $13 million from $117 million for 2009. Approximately $9 million of the improvement in earnings was due to the reversal in 2010, as approved by the regulator, of a provision taken in the fourth quarter of 2009 for the project cost overrun related to the conversion of Whistler customer appliances from propane to natural gas. Earnings also increased as a result of the higher allowed rate of return on common shareholders' equity ("ROE") at each of the Terasen Gas companies, effective July 1, 2009, and an increase in the deemed common equity component of the total capital structure at Terasen Gas, effective January 1, 2010.

Earnings at Canadian Regulated Electric Utilities were $164 million, up $15 million from $149 million for 2009. Excluding the favourable one-time $3 million corporate tax adjustment at FortisOntario in 2009, earnings were up $18 million year over year. The increase was driven by overall growth in electrical infrastructure investment, the increase in the allowed ROE at FortisBC effective January 1, 2010, customer growth at FortisAlberta, increased electricity sales at Newfoundland Power, and improved performance at FortisOntario due to the first full year of earnings' contribution from Algoma Power and lower effective corporate income taxes. Earnings for the year, however, reflected additional operating expenses of $1 million after tax at Newfoundland Power associated with restoration work post Hurricane Igor, the impact of a weather-related decrease in electricity sales at FortisBC and lower net transmission revenue at FortisAlberta.

Caribbean Regulated Electric Utilities contributed $23 million to earnings compared to $27 million for 2009. The decrease was largely due to the unfavourable impact of foreign currency translation and poor financial performance at Belize Electricity where regulatory challenges continue to impede the utility's ability to earn a fair and reasonable return. In 2010 the utility contributed just $1.5 million to earnings of Fortis. In the course of normal operations, Belize Electricity would be expected to contribute approximately $10 million annually to the Corporation's consolidated earnings. Results for 2010 also reflected continued lower-than-average annual electricity sales growth, due to persistent challenging economic conditions in the Caribbean region and the negative effect on air conditioning load of cooler-than-normal temperatures experienced on Grand Cayman in the second half of 2010. Annualized electricity sales growth for Caribbean Regulated Electric Utilities was 0.9% in 2010 compared to 2% in 2009.

Non-Regulated Fortis Generation contributed $20 million to earnings, up $4 million from 2009 mainly due to increased hydroelectric production in Belize, as a result of the commissioning of the 19-MW Vaca facility in March 2010 and higher rainfall, and lower finance charges, partially offset by lower earnings from the Rankine hydroelectric generating facility in Ontario due to the expiry of the water rights in April 2009.

Fortis Properties delivered earnings of $26 million, up $2 million from 2009 mainly due to lower effective corporate income taxes.

Corporate and other expenses were $78 million compared to $71 million for 2009. The increase was due to dividends associated with the $250 million First Preference Shares, Series H issued in January 2010 and business development costs, partially offset by lower finance charges. 

Earnings for the fourth quarter were $85 million, or $0.49 per common share, up from $81 million, or $0.48 per common share, for the same quarter in 2009. The increase was mainly due to improved performance at Canadian Regulated Electric Utilities, non-regulated hydroelectric generation operations in Belize and lower effective corporate income taxes at Fortis Properties, partially offset by lower earnings from the Terasen Gas companies and Caribbean Regulated Electric Utilities. Improved performance at Canadian Regulated Electric Utilities was driven by overall growth in electrical infrastructure investment combined with customer growth at FortisAlberta and the higher allowed ROE at FortisBC. Earnings were lower quarter over quarter at the Terasen Gas companies, mainly as a result of higher regulator-approved operating expenses and the timing of the spending of these increased expenses, and at Caribbean Regulated Electric Utilities, due to lower electricity sales associated with cooler-than-normal temperatures and poor financial performance at Belize Electricity. Earnings for the fourth quarter of 2009 were reduced by $5 million related to a provision taken in the fourth quarter of 2009 for the project cost overrun related to the conversion of Whistler customer appliances from propane to natural gas but were favourably impacted by a one-time $3 million corporate tax adjustment at FortisOntario. 

Customer rates have been set, effective January 1, 2011, for the four largest utilities. The allowed ROE for 2011 at Terasen Gas, FortisBC and FortisAlberta is 9.5%, 9.9% and an interim 9.0%, respectively, unchanged from each utility's allowed ROE for 2010. The allowed ROE at FortisAlberta has been declared interim pending the outcome of a proceeding to review capital structure and finalize the allowed ROE for 2011, which has commenced. The allowed ROE for 2011 at Newfoundland Power decreased to 8.38% from 9.0% as a result of the operation of the ROE automatic adjustment formula.

Standard and Poor's confirmed the Corporation's debt credit rating at A- in December and DBRS upgraded the Corporation's debt credit rating to A(low) from BBB(high) in October. The credit ratings reflect the Corporation's low business-risk profile, reasonable credit metrics, significant reduction in external debt at Terasen Inc. and the Corporation's demonstrated ability to acquire and integrate stable utility businesses financed on a conservative basis. 

Cash flow from operating activities was $783 million, up $146 million from $637 million for 2009 due to higher earnings, increased amortization costs collected through customer rates and favourable working capital changes year over year. 

Fortis and its utilities raised $525 million in long-term debt in 2010. In December Fortis privately placed 10-year US$125 million and 30-year US$75 million notes bearing interest at 3.53% and 5.26%, respectively. Proceeds from the notes were used to refinance indebtedness under the Corporation's committed credit facility related to amounts borrowed to repay maturing debt and for general corporate purposes. In the fourth quarter, FortisAlberta, Terasen Gas (Vancouver Island) and FortisBC issued unsecured debentures at terms of $125 million 40-year 4.8%, $100 million 30-year 5.2% and $100 million 40-year 5.0%, respectively. Proceeds from the debentures were mainly used to repay borrowings under the utilities' committed credit facilities incurred to finance their capital expenditure programs.

"Fortis utilities are busy building the infrastructure needed to meet our customers' energy needs. Our capital program is estimated at $1.2 billion for 2011 and near $5.5 billion over the next five years, driven by investment in infrastructure at our regulated utilities in western Canada and the Waneta Expansion Project," says Mr. Marshall.

"We will continue to pursue acquisitions of regulated electric and natural gas utilities in the United States and Canada that will add value for our shareholders, ever mindful that the priority of Fortis is to meet our obligation to serve customers," he concludes.

Financial Highlights

For the three and 12 months ended December 31, 2010

Dated February 10, 2011

FORWARD-LOOKING STATEMENT

The following fourth quarter 2010 media release should be read in conjunction with the Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") and audited consolidated financial statements for the year ended December 31, 2009 included in the Corporation's 2009 Annual Report. Financial information in this material has been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") and is presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in this fourth quarter 2010 media release within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs and is based on information currently available to the Corporation's management. The forward-looking information in this fourth quarter 2010 media release includes, but is not limited to, statements regarding: the expected increase in the total capital cost of the Fraser River South Bank South Arm Rehabilitation Project at Terasen Gas Inc.; the expected timing of the filing of regulatory applications and receipt of regulatory decisions; the expected timing of the close of the sale of the joint-use poles at Newfoundland Power; the expected timing of receipt of the court decision pertaining to Belize Electricity's June 2008 Final Decision; the expected total capital cost of FortisAlberta's Automated Meter Infrastructure Project; the expected deferred replacement energy costs at Maritime Electric to the end of February 2011;

the expected total capital cost for the construction of the 335-megawatt Waneta Expansion hydroelectric generating facility and its expected completion date; expected consolidated gross capital expenditures for 2011 and in total over the next five years; the expectation that Fortis will become a US Securities and Exchange Commission Issuer by December 31, 2011 and will adopt US generally accepted accounting principles effective January 1, 2012; and the expectation that the Corporation's significant capital program should drive growth in earnings and dividends. The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major event; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no material capital project and financing cost overrun related to the construction of the Waneta Expansion; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the commodity cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in interest rates and foreign exchange rates; no significant variability in interest rates; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas supply; the continued ability to fund defined benefit pension plans; the absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; maintenance of information technology infrastructure; favourable relations with First Nations; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.

The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include, but are not limited to: regulatory risk; operating and maintenance risks; capital project budget overruns and financing risk in the Corporation's non-regulated business; economic conditions; capital resources and liquidity risk; weather and seasonality; commodity price risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; competitiveness of natural gas; natural gas supply; defined benefit pension plan performance and funding requirements; environmental risks; insurance coverage risk; loss of licences and permits; loss of service area; changes in the current assumptions and expectations associated with the transition to new accounting standards; changes in tax legislation; information technology infrastructure; an ultimate resolution of the expropriation of the assets of the Exploits River Hydro Partnership that differs from what is currently expected by management; an unexpected outcome of legal proceedings currently against the Corporation; relations with First Nations; labour relations; and human resources. For additional information with respect to the Corporation's risk factors, reference should be made to the Corporation's continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and to the heading "Business Risk Management" in the MD&A for the year ended December 31, 2009 and for the three and nine months ended September 30, 2010, and as otherwise disclosed in this fourth quarter 2010 media release.

All forward-looking information in this fourth quarter 2010 media release is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.

CORPORATE OVERVIEW AND FINANCIAL HIGHLIGHTS

Fortis is the largest investor-owned distribution utility in Canada, serving approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia, Canada. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State, and hotels and commercial office and retail space primarily in Atlantic Canada. In 2010 the Corporation's electricity distribution systems met a combined peak demand of approximately 5,162 megawatts ("MW") and its gas distribution system met a peak day demand of 1,421 terajoules ("TJ"). For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's 2009 annual audited consolidated financial statements.

The key goals of the Corporation's regulated utilities are to operate sound gas and electricity distribution systems, deliver gas and electricity safely and reliably to customers at the lowest reasonable cost and conduct business in an environmentally responsible manner. The Corporation's main business, utility operations, is highly regulated. It is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets.

Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. Key financial highlights, including earnings by reportable segment, for the fourth quarters and years ended December 31, 2010 and December 31, 2009 are provided in the following tables. 

Financial Highlights (Unaudited)	Quarter			Annual
Periods Ended December 31	2010	2009	Variance	2010	2009	Variance
Revenue ($ millions)	1,036	1,020	16	3,664	3,643	21
Cash Flow from Operating Activities ($ millions)	201	71	130	783	637	146
Net Earnings Attributable to Common Equity Shareholders ($ millions)	85	81	4	285	262	23
Basic Earnings per Common Share ($)	0.49	0.48	0.01	1.65	1.54	0.11
Diluted Earnings per Common Share ($)	0.47	0.46	0.01	1.62	1.51	0.11
Weighted Average Number of Common Shares Outstanding (millions)	173.9	170.9	3.0	172.9	170.2	2.7

Segmented Net Earnings Attributable to Common Equity Shareholders (Unaudited)
Periods Ended December 31		Quarter						Annual
($ millions)		2010		2009		Variance		2010		2009		Variance
Regulated Gas Utilities - Canadian
	Terasen Gas Companies (1)	45		48		(3	)	130		117		13
Regulated Electric Utilities - Canadian
	Fortis  Alberta	17		15		2		68		60		8
	FortisBC (2)	10		8		2		42		37		5
	Newfoundland Power	9		8		1		35		32		3
	Other Canadian (3)	5		7		(2	)	19		20		(1	)
		41		38		3		164		149		15
Regulated Electric Utilities - Caribbean (4)		5		7		(2	)	23		27		(4	)
Non-Regulated - Fortis Generation (5)		5		2		3		20		16		4
Non-Regulated - Fortis Properties (6)		7		5		2		26		24		2
Corporate and Other (7)		(18	)	(19	)	1		(78	)	(71	)	(7	)
Net Earnings Attributable to Common Equity Shareholders		85		81		4		285		262		23

(1) Comprised of Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI")

(2) Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants and the distribution system owned by the City of Kelowna. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned partnership, Walden Power Partnership.

(3) Includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and, from October 2009, Algoma Power.

(4) Includes Belize Electricity, in which Fortis holds an approximate 70% controlling interest; Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 59% controlling interest; and wholly owned Fortis Turks and Caicos.

(5) Includes the financial results of non-regulated assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State, with a combined generating capacity of 139 megawatts ("MW"), mainly hydroelectric. Results reflect contribution from the Vaca hydroelectric generating facility in Belize from March 2010 when the facility was commissioned. Prior to May 1, 2009, the financial results of Fortis reflected earnings' contribution associated with the Corporation's 75-MW water-right entitlement on the Niagara River in Ontario related to the Rankine hydroelectric generating facility. The water rights expired on April 30, 2009 at the end of a 100-year term. Additionally, prior to February 12, 2009, the financial results of the hydroelectric generation operations in central Newfoundland were consolidated in the financial statements of Fortis. Effective February 12, 2009, the Corporation discontinued the consolidation method of accounting for the generation operations in central Newfoundland due to the Corporation no longer having control over the operations and cash flows, as a result of the expropriation of the assets of the Exploits River Hydro Partnership by the Government of Newfoundland and Labrador. For a further discussion of this matter, refer to the "Critical Accounting Estimates – Contingencies" section of the MD&A for the year ended December 31, 2009.

(6) Fortis Properties owns and operates 21 hotels, comprised of more than 4,100 rooms, in eight Canadian provinces and approximately 2.7 million square feet of commercial office and retail space primarily in Atlantic Canada.

(7) Includes Fortis net corporate expenses, net expenses of non-regulated Terasen Inc. ("Terasen") corporate-related activities and the financial results of Terasen's 30% ownership interest in CustomerWorks Limited Partnership ("CWLP") and of Terasen's non-regulated wholly owned subsidiary Terasen Energy Services Inc. ("TES")

SEGMENTED RESULTS OF OPERATIONS

REGULATED GAS UTILITIES - CANADIAN

TERASEN GAS COMPANIES

Gas Volumes by Major Customer Category (Unaudited)
Periods Ended December 31	Quarter				Annual
(TJ)	2010	2009	Variance		2010	2009	Variance
Core – Residential and Commercial	37,035	42,701	(5,666	)	113,635	125,238	(11,603	)
Industrial	1,551	1,659	(108	)	5,259	6,038	(779	)
Total Sales Volumes	38,586	44,360	(5,774	)	118,894	131,276	(12,382	)
Transportation Volumes	18,405	16,937	1,468		60,363	60,067	296
Throughput under Fixed Revenue Contracts	3,407	3,703	(296	)	13,765	15,887	(2,122	)
Total Gas Volumes	60,398	65,000	(4,602	)	193,022	207,230	(14,208	)

Factors Contributing to Gas Volumes Variance

Quarter over Quarter

Unfavourable

• Lower average gas consumption by residential and commercial customers, as a result of warmer temperatures

Favourable

• Higher transportation volumes, as a result of the favourable impact of continued improving economic conditions in the forestry sector, including a pulp and paper mill customer returning to service

Factors Contributing to Gas Volumes Variance

Year over Year

Unfavourable

• Lower average gas consumption by residential, commercial and industrial customers, as a result of warmer average temperatures in 2010 compared to 2009

• Lower volumes under fixed revenue contracts, mainly due to reduced demand from a large customer resulting from changing their gas supply requirements from peak demand to emergency demand

Net customer additions were approximately 9,400 for 2010 compared to 8,200 for 2009. Customer additions increased year over year due to increased building activity. 

The Terasen Gas companies earn approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or for the transportation only of natural gas.

As a result of the operation of regulator-approved deferral mechanisms, changes in consumption levels and energy supply costs from those forecast to set customer gas rates do not materially affect earnings.

Due to natural gas consumption patterns, earnings at the Terasen Gas companies are highest in the first and fourth quarters. As a result of seasonality, interim earnings are not indicative of annual earnings.

Financial Highlights (Unaudited)
Periods Ended December 31	Quarter				Annual
($ millions)	2010	2009	Variance		2010	2009	Variance
Revenue	480	497	(17	)	1,547	1,663	(116	)
Energy Supply Costs	277	300	(23	)	863	1,022	(159	)
Operating Expenses	87	79	8		288	268	20
Amortization	27	26	1		108	102	6
Finance Charges	29	30	(1	)	113	121	(8	)
Corporate Taxes	15	14	1		45	33	12
Earnings	45	48	(3	)	130	117	13

Factors Contributing to Revenue Variance

Quarter over Quarter

Unfavourable

• Lower average gas consumption by residential and commercial customers

• Lower commodity cost of natural gas charged to customers

Favourable

• The increase in customer delivery rates, effective January 1, 2010, relating to the increase in the deemed common equity component of the total capital structure ("equity component") for Terasen Gas Inc. ("TGI") to 40% from 35% and increased regulator-approved operating expenses and amortization costs recoverable from customers

Factors Contributing to Revenue Variance

Year over Year

Unfavourable

• The same factors as for the quarter discussed above

Favourable

• The increase in customer delivery rates, effective January 1, 2010, which mainly reflected: (i) the impact of the increase in the allowed rate of return on common shareholders' equity ("ROE") to 9.50% from 8.47% for TGI and to 10.00% for Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI") from 9.17% and 8.97%, respectively, for a full year in 2010 compared to half a year in 2009; (ii) the increase in the equity component for TGI to 40% from 35%, effective January 1, 2010; and (iii) higher regulator-approved operating expenses and amortization costs recoverable from customers. The increase in the allowed ROEs for the Terasen Gas companies was effective July 1, 2009.

Factors Contributing to Earnings Variance

Quarter over Quarter

Unfavourable

• Higher operating expenses due to the timing of the expenses during 2010, with a higher weighting in the fourth quarter of 2010, combined with: (i) increased labour and employee-benefit costs; (ii) new initiatives agreed to in the regulator-approved Negotiated Settlement Agreement ("NSA") related to 2010 and 2011 revenue requirements resulting in higher planned maintenance and operating activities in 2010 compared to 2009; (iii) the expensing of asset removal costs to operating expenses, effective January 1, 2010, as a result of the NSA; and (iv) lower capitalized overhead costs, due to a reduction in the capitalization rate, also as a result of the NSA. The asset removal costs and higher expensed overhead costs were approved for collection in customer delivery rates. Prior to 2010, asset removal costs were recorded against accumulated amortization. 

• Increased amortization costs due to higher amortization rates and continued investment in utility capital assets. Amortization rates for 2010 were determined and approved by the regulator upon review of a recent depreciation study. The increase in amortization costs is being collected in customer delivery rates.

• Higher effective corporate income taxes, mainly due to higher non-deductible expenses in 2010 compared to 2009, partially offset by a lower statutory income tax rate

Favourable

• The increase in customer delivery rates, effective January 1, 2010, as discussed above for the quarterly revenue variance

• The expensing of a provision taken in the fourth quarter of 2009 of approximately $6 million ($5 million after tax) of the project cost overrun related to the conversion of Whistler customer appliances from propane to natural gas 

• Lower finance charges, due to lower average credit facility borrowings

Factors Contributing to Earnings Variance

Year over Year

Favourable

• The increase in customer delivery rates, effective January 1, 2010, as discussed above for the annual revenue variance

• Lower finance charges, for the same reason as for the quarter discussed above

• The favourable $9 million impact of the regulator-approved reversal in the third quarter of 2010 of most of the project cost overrun ($5 million pre-tax, $4 million after tax) related to the conversion of Whistler customer appliances, which was previously provided for and expensed in the fourth quarter of 2009 ($6 million pre-tax, $5 million after tax)

Unfavourable

• Increased operating expenses, amortization costs and higher effective corporate income taxes for the same reasons as for the quarter discussed above

In December 2010 TGVI issued 30-year $100 million 5.20% unsecured debentures, the net proceeds of which were used to repay committed credit facility borrowings incurred in support of the utility's capital expenditure program.

For an update on material regulatory decisions and applications pertaining to the Terasen Gas companies for the fourth quarter of 2010, refer to the "Regulatory Highlights" section of this fourth quarter 2010 media release.

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited)	Quarter					Annual
Periods Ended December 31	2010		2009		Variance	2010		2009		Variance
Energy Deliveries (gigawatt hours ("GWh"))	4,255		4,129		126	15,866		15,865		1
($ millions)
Revenue	99		86		13	388		331		57
Operating Expenses	37		34		3	141		132		9
Amortization	32		24		8	126		94		32
Finance Charges	14		14		-	54		50		4
Corporate Tax Recovery	(1	)	(1	)	-	(1	)	(5	)	4
Earnings	17		15		2	68		60		8

Factors Contributing to Energy Deliveries Variance

Quarter over Quarter

Favourable

• Higher energy deliveries to commercial and oil and gas customers, due to increased oil and gas activities and an increase in the number of customers

Unfavourable

• Decreased energy deliveries to farm and irrigation, and residential customers, mainly due to lower average consumption resulting from relatively milder temperatures and increased rainfall, partially offset by the impact of an increase in the number of customers 

Factors Contributing to Energy Deliveries Variance

Year over Year

Favourable

• Higher energy deliveries to residential, commercial and oil and gas customers, mainly associated with an increase in the number of customers

Unfavourable

• Decreased energy deliveries to farm and irrigation customers, mainly due to lower average consumption resulting from relatively milder temperatures and increased rainfall, partially offset by an increase in the number of customers 

• Decreased energy deliveries to other industrial customers, mainly due to lower average consumption resulting from the impact of unfavourable economic conditions, and a reduction in the number of customers

The total number of customers at FortisAlberta increased approximately 11,000 from 2009, reaching approximately 491,000 as at December 31, 2010.

As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenues are a function of numerous variables, many of which are independent of actual energy deliveries.

Factors Contributing to Revenue Variance

Quarter over Quarter and Year over Year

Favourable

• Accrued electricity rate revenue combined with a 7.5% average increase in base customer electricity rates, effective January 1, 2010, associated with the 2010-2011 regulatory rate decision. The customer rate revenue accrual and rate increase were primarily due to ongoing investment in electrical infrastructure, and higher regulator-approved amortization costs, operating expenses and finance charges recoverable from customers.

• Customer growth

Unfavourable

• Electricity rate revenue in the fourth quarter of 2009 reflected the favourable $3 million retroactive impact, relating to the first three quarters of 2009, of the increase in the allowed ROE and equity component, effective January 1, 2009.

• Lower net transmission revenue of approximately $5 million year over year. Effective January 1, 2010, as a result of the 2010-2011 regulatory rate decision, all transmission costs and revenue are deferred to be recovered from, or refunded to, customers in future rates.

Collection of the rate revenue accrual began with new final customer rates and riders, effective January 1, 2011, as approved by the regulator.

Factors Contributing to Earnings Variance

Quarter over Quarter and Year over Year

Favourable

• The increase in electricity distribution rate revenue related to ongoing investment in electrical infrastructure, customer growth and higher regulator-approved expenses recoverable from customers.

Unfavourable

• Increased amortization costs associated with higher overall amortization rates, as approved in the 2010-2011 regulatory rate decision, and continued investment in utility capital assets, partially offset by the impact of the commencement, in 2010, of the capitalization of amortization for vehicles and tools used in the construction of other assets, as approved by the regulator

• Increased operating expenses, mainly due to higher general operating expenses, higher contracted labour costs for the quarter and higher internal labour costs for the year

• Higher finance charges for the year, due to higher debenture borrowings in support of FortisAlberta's significant capital expenditure program and the impact of an increase in interest rates on credit facility borrowings, partially offset by lower average credit facility borrowings and increased capitalized allowance for funds used during construction

• Lower net transmission revenue for the year, for the same reason as for the revenue variance discussed above

• Lower corporate tax recoveries for the year, due to lower future income tax recoveries associated with changes in net customer deferrals and a favourable adjustment to current income taxes of approximately $2 million during the second quarter of 2009

• Electricity rate revenue in the fourth quarter of 2009 reflected the favourable $3 million retroactive impact, relating to the first three quarters of 2009, of the increase in the allowed ROE and equity component, effective January 1, 2009.

In October 2010 FortisAlberta issued 40-year $125 million 4.80% unsecured debentures, the net proceeds of which were used to repay committed credit facility borrowings that were incurred primarily to finance capital expenditures, and for general corporate purposes.

For an update on material regulatory decisions and applications pertaining to FortisAlberta for the fourth quarter of 2010, refer to the "Regulatory Highlights" section of this fourth quarter 2010 media release.

FORTISBC

Financial Highlights (Unaudited)	Quarter				Annual
Periods Ended December 31	2010	2009	Variance		2010	2009	Variance
Electricity Sales (GWh)	847	859	(12	)	3,046	3,157	(111	)
($ millions)
Revenue	73	69	4		266	253	13
Energy Supply Costs	23	22	1		73	72	1
Operating Expenses	21	20	1		73	70	3
Amortization	10	9	1		41	37	4
Finance Charges	8	8	-		32	32	-
Corporate Taxes	1	2	(1	)	5	5	-
Earnings	10	8	2		42	37	5

Factors Contributing to Electricity Sales Variance

Quarter over Quarter and Year over Year

Unfavourable

• Lower consumption, primarily due to unfavourable weather conditions

Favourable

• Customer growth

Factors Contributing to Revenue Variance

Quarter over Quarter and Year over Year

Favourable

• A 6.0% increase in customer electricity rates, effective January 1, 2010, mainly reflecting an increase in the allowed ROE to 9.90% for 2010, up from 8.87% for 2009, and ongoing investment in electrical infrastructure

• A 2.9% increase in customer electricity rates, effective September 1, 2010, as a result of the flow through to customers of increased power purchase costs charged by BC Hydro

• Increased performance-based rate-setting ("PBR") incentive adjustments receivable from customers

• Higher pole attachment revenue for the year

Unfavourable

• The 1.4% and 3.5% decrease in electricity sales for the quarter and year, respectively

Factors Contributing to Earnings Variance

Quarter over Quarter

Favourable

• The increase in customer electricity rates, effective January 1, 2010

• Increased PBR incentive adjustments

• Lower effective corporate income taxes, due to higher deductions from income for income tax purposes compared to accounting purposes in 2010 versus 2009, and a lower statutory income tax rate

Unfavourable

• Higher energy supply costs associated with the impact of higher average prices for purchased power

• Higher operating expenses primarily due to increased labour costs and general inflationary increases, along with an increase in certain other operating expenses due to the timing of operating and maintenance projects in 2010 and their related expenditures

• Increased amortization costs associated with continued investment in utility capital assets

• Decreased electricity sales

Factors Contributing to Earnings Variance

Year over Year

Favourable

• The same factors as for the quarter discussed above

Unfavourable

• Higher energy supply costs, for the same reason as for the quarter discussed above

• Increased water fees and property taxes, and higher operating and maintenance costs due to increased labour costs and general inflationary increases, partially offset by an increase in capitalized overhead costs

• Increased amortization costs, for the same reason as for the quarter discussed above

• Decreased electricity sales

• Lower earnings' contribution from non-regulated operating, maintenance and management services, primarily due to higher operating costs

In November 2010 FortisBC issued 40-year $100 million 5.00% unsecured debentures, the net proceeds of which were used to repay committed credit facility borrowings and finance capital expenditures and working capital requirements.

For an update on material regulatory decisions and applications pertaining to FortisBC for the fourth quarter of 2010, refer to the "Regulatory Highlights" section of this fourth quarter 2010 media release.

NEWFOUNDLAND POWER

Financial Highlights (Unaudited)	Quarter			Annual
Periods Ended December 31	2010	2009	Variance	2010	2009	Variance
Electricity Sales (GWh)	1,488	1,474	14	5,419	5,299	120
($ millions)
Revenue	152	146	6	555	527	28
Energy Supply Costs	102	99	3	358	346	12
Operating Expenses	15	13	2	62	52	10
Amortization	12	12	-	47	45	2
Finance Charges	9	9	-	36	35	1
Corporate Taxes	4	4	-	16	16	-
	10	9	1	36	33	3
Non-Controlling Interests	1	1	-	1	1	-
Earnings	9	8	1	35	32	3

Factors Contributing to Electricity Sales Variance

Quarter over Quarter

Favourable

• Customer growth

Unfavourable

• Lower average consumption mainly due to milder temperatures and lower activity in the commercial sector

Factors Contributing to Electricity Sales Variance

Year over Year

Favourable

• Customer growth and higher average consumption

Factors Contributing to Revenue Variance

Quarter over Quarter and Year over Year

Favourable

• An average 3.5% increase in customer electricity rates, effective January 1, 2010, mainly reflecting an increase in the allowed ROE to 9.00% for 2010, up from 8.95% for 2009; ongoing investment in electrical infrastructure; and higher regulator-approved expenses, including pension costs, recoverable from customers

• A 1.0% and 2.3% increase in electricity sales for the quarter and year, respectively

Factors Contributing to Earnings Variance

Quarter over Quarter

Favourable

• The average 3.5% increase in customer electricity rates, effective January 1, 2010

• Increased electricity sales

• Lower effective corporate income taxes, due to a reduction in statutory income tax rates and higher deductions from income for income tax purposes compared to accounting purposes in 2010 versus 2009

Unfavourable

• Increased energy supply costs associated with the Company's hydroelectric generating facilities

• Higher pension costs and inflationary and wage increases

Factors Contributing to Earnings Variance

Year over Year

Favourable

• The same factors as for the quarter discussed above

Unfavourable

• The same factors as for the quarter discussed above

• Incremental operating costs of approximately $1.5 million incurred in the third quarter of 2010 as a result of Hurricane Igor, which impacted over half of the Company's service territory 

• Increased conservation and higher retirement and severance expenses, partially offset by lower regulatory costs and higher capitalized overhead costs

• Increased amortization costs associated with continued investment in utility capital assets

• Higher finance charges associated with interest expense on the $65 million 6.606% bonds issued in May 2009

For an update on material regulatory decisions and applications pertaining to Newfoundland Power for the fourth quarter of 2010, refer to the "Regulatory Highlights" section of this fourth quarter 2010 media release.

OTHER CANADIAN ELECTRIC UTILITIES ⁽¹⁾

Financial Highlights (Unaudited)	Quarter					Annual
Periods Ended December 31	2010	2009		Variance		2010	2009	Variance
Electricity Sales (GWh)	578	582		(4	)	2,328	2,195	133
($ millions)
Revenue	87	79		8		331	285	46
Energy Supply Costs	59	50		9		215	183	32
Operating Expenses	12	12		-		45	38	7
Amortization	5	5		-		23	19	4
Finance Charges	5	6		(1	)	21	19	2
Corporate Tax Expense (Recovery)	1	(1	)	2		8	6	2
Earnings	5	7		(2	)	19	20	(1	)

(1) Includes Maritime Electric and FortisOntario. FortisOntario includes financial results of Algoma Power from October 8, 2009, the date of acquisition.

Factors Contributing to Electricity Sales Variance

Quarter over Quarter

Unfavourable

• Lower average consumption in Ontario, mainly due to reduced space heating load as a result of warmer temperatures

Favourable

• Higher consumption on Prince Edward Island ("PEI") due to residential customer growth, warmer temperatures favourably impacting crop storage cooling for the farming sector and increased processing activity in the commercial sector

Factors Contributing to Electricity Sales Variance

Year over Year

Favourable

• Higher electricity sales at Algoma Power, mainly due to contribution for a full year in 2010 compared to three months in 2009. Algoma Power was acquired by FortisOntario in October 2009.

Factors Contributing to Revenue Variance

Quarter over Quarter

Favourable

• An average 3.8% increase in customer electricity rates at Algoma Power, effective December 1, 2010

• An increase at Maritime Electric, effective August 1, 2010, in the base amount of energy-related costs being expensed and collected from customers and recorded in revenue through the basic rate component of customer billings

• The flow through in customer electricity rates of higher energy supply costs at FortisOntario

Unfavourable

• The 0.7% decrease in electricity sales

Factors Contributing to Revenue Variance

Year over Year

Favourable

• Higher revenue of approximately $27 million from Algoma Power, mainly due to a full year of revenue contribution in 2010 compared to three months in 2009 and the average 3.8% increase in customer electricity rates at Algoma Power, effective December 1, 2010

• The flow through in customer electricity rates of higher energy supply costs at FortisOntario

• The increase at Maritime Electric in the base amount of energy-related costs being collected from customers, for the same reason as for the quarter discussed above

• Increases in the base component of customer electricity distribution rates at Fort Erie, Gananoque and Port Colborne in Ontario, effective May 1, 2009 and May 1, 2010

Factors Contributing to Earnings Variance

Quarter over Quarter and Year over Year

Unfavourable

• A one-time favourable adjustment of approximately $3 million to future income taxes related to prior periods recorded during the fourth quarter of 2009 at FortisOntario

Favourable

• Earnings' contribution from Algoma Power increased $0.8 million for the quarter and $1.3 million for the year. The increase for the quarter was mainly due to a reduction in operating expenses resulting from the recognition of capitalized overhead expenses during the fourth quarter of 2010 relating to the full year. The increase for the year was primarily due to a full year of earnings' contribution from Algoma Power in 2010 and the impact of the average 3.8% customer electricity rate increase at Algoma Power, effective December 1, 2010.

• Lower finance charges at Maritime Electric, due to lower short-term borrowing rates and the repayment of a maturing $15 million first mortgage bond in May 2010 that carried a 12% interest rate

• Lower effective corporate income taxes at FortisOntario, excluding the one-time $3 million corporate tax adjustment in the fourth quarter of 2009, due to higher deductions from income for income tax purposes compared to accounting purposes in 2010 versus 2009

For an update on material regulatory decisions and applications pertaining to Maritime Electric and FortisOntario for the fourth quarter of 2010, refer to the "Regulatory Highlights" section of this fourth quarter 2010 media release.

REGULATED ELECTRIC UTILITIES - CARIBBEAN ⁽¹⁾

Financial Highlights (Unaudited)	Quarter				Annual
Periods Ended December 31	2010	2009	Variance		2010	2009	Variance
Average US:CDN Exchange Rate (2)	1.01	1.06	(0.05	)	1.03	1.13	(0.10	)
Electricity Sales (GWh)	270	291	(21	)	1,150	1,140	10
($ millions)
Revenue	84	85	(1	)	335	339	(4	)
Energy Supply Costs	51	50	1		201	192	9
Operating Expenses	13	13	-		48	54	(6	)
Amortization	9	8	1		36	37	(1	)
Finance Charges	5	4	1		17	16	1
Corporate Taxes	-	-	-		1	2	(1	)
	6	10	(4	)	32	38	(6	)
Non-Controlling Interests	1	3	(2	)	9	11	(2	)
Earnings	5	7	(2	)	23	27	(4	)

(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos

(2) The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00. The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar.

Factors Contributing to Electricity Sales Variance

Quarter over Quarter

Unfavourable

• Decreased air conditioning load, as a result of lower average temperatures experienced on Grand Cayman and in the Turks and Caicos Islands and Belize

Favourable

• Customer growth at Belize Electricity

• Incremental load associated with a new system-connected medical facility and condominium complex in the Turks and Caicos Islands

Factors Contributing to Electricity Sales Variance

Year over Year

Favourable

• The same factors as for the quarter discussed above

• In July 2010 Fortis Turks and Caicos achieved a new record peak load of 31 MW

Unfavourable

• Decreased air conditioning load, as a result of lower average temperatures experienced on Grand Cayman during the second half of 2010

• Reduced residential customer base at Fortis Turks and Caicos, due to construction workers leaving the Turks and Caicos Islands

• Tempered growth due to continuing challenging economic conditions in the region

Factors Contributing to Revenue Variance
Quarter over Quarter

Unfavourable

• Approximately $4 million unfavorable foreign exchange associated with the translation of foreign currency-denominated revenue, due to the weakening of the US dollar relative to the Canadian dollar

• An overall 7.2% decrease in electricity sales

Favourable

• The flow through in customer electricity rates of higher energy supply costs at Caribbean Utilities, due to an increase in the cost of fuel

Factors Contributing to Revenue Variance
Year over Year

Unfavourable

• Approximately $33 million associated with unfavourable foreign currency translation for the same reason as for the quarter discussed above

• The unfavourable approximate $1.5 million year-over-year impact of the reversal of the Court of Appeal judgment at Fortis Turks and Caicos related to a customer-rate-classification matter

Favourable

• The flow through in customer electricity rates of higher energy supply costs at Caribbean Utilities, for the same reason as for the quarter discussed above

• An overall 0.9% increase in electricity sales

• A 2.4% increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009

Factors Contributing to Earnings Variance
Quarter over Quarter

Unfavourable

• Higher operating expenses at Belize Electricity, excluding the impact of foreign exchange, mainly due to increased legal fees associated with continued regulatory challenges

• Decreased electricity sales

• Approximately $0.5 million associated with unfavourable foreign currency translation

• Higher amortization costs, excluding the impact of foreign exchange, mainly due to a change in amortization estimates at Fortis Turks and Caicos favourably impacting amortization costs by approximately $1.5 million during the fourth quarter of 2009

Factors Contributing to Earnings Variance
Year over Year

Unfavourable

• Approximately $3 million associated with unfavourable foreign currency translation

• Higher operating expenses at Belize Electricity, excluding the impact of foreign exchange, mainly due to increased legal fees associated with continued regulatory challenges

• Higher finance charges, excluding the impact of foreign exchange, mainly associated with interest expense on the US$40 million 7.5% unsecured notes issued in May 2009 and July 2009 at Caribbean Utilities, and lower capitalized allowance for funds used during construction, combined with higher interest expense on regulatory liabilities at Belize Electricity

• Higher amortization costs, excluding the impact of foreign exchange, mainly associated with continued investment in utility capital assets

• The favourable impact on energy supply costs in 2009, due to a change in the methodology for calculating the cost of fuel recoverable from customers at Fortis Turks and Caicos

• The unfavourable approximate $1.5 million year-over-year impact of the reversal of the Court of Appeal judgment at Fortis Turks and Caicos related to a customer-rate-classification matter

Favourable

• Excluding the impact of foreign exchange, lower operating expenses at Caribbean Utilities due to an increased focus on capital projects in 2010 which changed the timing of certain maintenance activities combined with higher capitalized overhead, and lower operating expenses at Fortis Turks and Caicos associated with a lower provision for bad debts

• Reduced generator maintenance costs at Fortis Turks and Caicos

• Increased electricity sales

For an update on material regulatory decisions and applications pertaining to Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos for the fourth quarter of 2010, refer to the "Regulatory Highlights" section of this fourth quarter 2010 media release.

NON-REGULATED - FORTIS GENERATION ⁽¹⁾

Financial Highlights (Unaudited)	Quarter				Annual
Periods Ended December 31	2010(2)	2009		Variance	2010(2)	2009 (3)	Variance
Energy Sales (GWh)	137	87		50	427	583	(156	)
($ millions)
Revenue	9	5		4	36	39	(3	)
Energy Supply Costs	-	-		-	1	2	(1	)
Operating Expenses	2	2		-	9	11	(2	)
Amortization	1	1		-	4	5	(1	)
Finance Charges	-	-		-	-	2	(2	)
Corporate Taxes	1	1		-	2	3	(1	)
	5	1		4	20	16	4
Non-Controlling Interests	-	(1	)	1	-	-	-
Earnings	5	2		3	20	16	4

(1) Includes the results of non-regulated assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State. The reporting currency for financial results in Belize and Upper New York State is the US dollar.

(2) Results reflect contribution from the Vaca hydroelectric generating facility in Belize from March 2010 when the facility was commissioned.

(3) Results reflect contribution from the Rankine hydroelectric generating facility in Ontario until April 30, 2009, when the Rankine water rights expired at the end of a 100-year term.

Factors Contributing to Energy Sales Variance

Quarter over Quarter

Favourable

• Higher rainfall and the commissioning of the Vaca hydroelectric generating facility in Belize in March 2010. Production by the facility was 28 GWh for the fourth quarter of 2010. 

• Higher production in Upper New York State, Ontario and British Columbia, due to higher rainfall

Factors Contributing to Energy Sales Variance

Year over Year

Unfavourable

• The expiration on April 30, 2009 of the water rights of the Rankine hydroelectric generating facility in Ontario. Energy sales during 2009 included approximately 215 GWh related to Rankine.

• Lower energy sales related to central Newfoundland operations. Energy sales for 2009 included 19 GWh related to central Newfoundland operations up until February 12, 2009, at which time the consolidation method of accounting for these operations was discontinued as a consequence of the actions of the Government of Newfoundland and Labrador related to expropriation of the assets of the Exploits River Hydro Partnership (the "Exploits Partnership").

• Decreased production in Upper New York State, due to lower rainfall

Favourable

• Higher rainfall and the commissioning of the Vaca hydroelectric generating facility in Belize in March 2010. Production by the facility was 83 GWh for 2010.

• Higher production in British Columbia, due to higher rainfall

Factors Contributing to Revenue Variance

Quarter over Quarter

Favourable

• Higher production in all operating areas, led by Belize

• A higher average wholesale market energy sales rate per megawatt hour ("MWh") in Upper New York State, which was US$43.57 for the fourth quarter of 2010 compared to US$41.18 for the fourth quarter of 2009

• A higher average energy sales rate per MWh in Ontario, which was $70.00 for the fourth quarter of 2010 compared to $31.99 for the fourth quarter of 2009. Effective May 1, 2010, energy produced in Ontario is being sold under a fixed-price contract. Previously, energy was sold at market rates.

Factors Contributing to Revenue Variance

Year over Year

Unfavourable

• The loss of revenue subsequent to the expiration of the Rankine water rights on April 30, 2009

• The discontinuance of the consolidation method of accounting for the financial results of the Exploits Partnership on February 12, 2009

• Approximately $3 million unfavourable foreign exchange associated with the translation of US dollar-denominated revenue, due to the weakening of the US dollar relative to the Canadian dollar

• Lower production in Upper New York State

Favourable

• Higher production in Belize and British Columbia

• A higher average annual wholesale market energy sales rate per MWh in Upper New York State, which was US$43.12 for 2010 compared to US$38.54 for 2009

• A higher average annual energy sales rate per MWh in Ontario, which was $53.17 for 2010 compared to $34.43 for 2009

Factors Contributing to Earnings Variance

Quarter over Quarter

Favourable

• Higher production in all operating areas, led by Belize

• Higher average energy sales rates per MWh in Upper New York State and Ontario

Factors Contributing to Earnings Variance

Year over Year

Favourable

• Higher production in Belize

• Reduced finance charges, excluding the impact of foreign exchange, as a result of higher interest revenue associated with inter-company lending to regulated operations in Ontario, partially offset by higher interest expense associated with inter-company lending to finance the construction of the Vaca hydroelectric generating facility. Capitalization of interest during the construction period ended with the commissioning of the facility in 2010.

• Higher average annual energy sales rates per MWh in Upper New York State and Ontario, partially offset by lower production in Upper New York State

Unfavourable

• The expiration of the Rankine water rights. Earnings' contribution associated with the Rankine hydroelectric generating facility was approximately $3.5 million during 2009.

• Approximately $2 million associated with unfavourable foreign currency translation

NON-REGULATED - FORTIS PROPERTIES

Financial Highlights (Unaudited)
Periods Ended December 31	Quarter				Annual
($ millions)	2010	2009	Variance		2010	2009	Variance
Hospitality Revenue	40	38	2		160	155	5
Real Estate Revenue	17	16	1		66	64	2
Total Revenue	57	54	3		226	219	7
Operating Expenses	38	37	1		151	146	5
Amortization	5	5	-		18	17	1
Finance Charges	6	5	1		24	22	2
Corporate Taxes	1	2	(1	)	7	10	(3	)
Earnings	7	5	2		26	24	2

Factors Contributing to Revenue Variance

Quarter over Quarter

Favourable

• Higher revenue contribution from hotel properties in Atlantic Canada and central Canada

• A 2.7% increase in revenue per available room ("RevPAR") at the Hospitality Division to $70.76 for the fourth quarter of 2010 from $68.87 for the same quarter in 2009. RevPAR increased due to an overall 2.0% increase in the average room rate and an overall 0.8% increase in hotel occupancy. Average room rates increased in all regions, lead by operations in Atlantic Canada. Hotel occupancy at operations in Atlantic Canada and central Canada increased, while occupancy at operations in western Canada decreased.

• Revenue growth in all regions of the Real Estate Division, with the most significant increase being in Newfoundland, mainly due to rent increases

Unfavourable

• A decrease in the occupancy rate at the Real Estate Division to 94.5% as at December 31, 2010 from 96.2% as at December 31, 2009, mainly associated with operations in Newfoundland and New Brunswick

Factors Contributing to Revenue Variance

Year over Year

Favourable

• Revenue contribution from the Holiday Inn Select Windsor, acquired in April 2009, combined with higher revenue contribution from hotel properties in Atlantic Canada and central Canada, partially offset by lower revenue contribution from hotel properties in western Canada

• A 0.4% increase in RevPAR at the Hospitality Division to $76.83 for 2010 from $76.55 for 2009. RevPAR increased due to an overall 1.8% increase in the average room rate, partially offset by an overall 1.4% decrease in hotel occupancy. Average room rates at operations in western Canada and Atlantic Canada increased. Hotel occupancy at operations in western Canada decreased, while occupancy at operations in central Canada and Atlantic Canada increased. 

• Revenue growth in all regions of the Real Estate Division, with the most significant increases being in Newfoundland and Nova Scotia, mainly due to rent increases

Unfavourable

• Decreased occupancy rate at the Real Estate Division, for the same reason as for the quarter discussed above

Factors Contributing to Earnings Variance

Quarter over Quarter

Favourable

• Lower effective corporate income taxes associated with lower statutory income tax rates and their effect of reducing future income tax liability balances

• Improved performance at the Real Estate Division, mainly due to rent increases, and improved performance at hotel operations in Atlantic Canada and central Canada, driven by increased RevPAR as discussed above

Unfavourable

• Lower performance at hotel operations in western Canada, due to the continued unfavourable impact of the economic downturn on occupancies in this region

• Increased finance charges, due to higher debt levels and interest rates

Factors Contributing to Earnings Variance

Year over Year

Favourable

• Lower effective corporate income taxes, for the same reason as for the quarter discussed above

• Improved performance at the Real Estate Division, for the same reason as for the quarter discussed above

• Contribution from the Holiday Inn Select Windsor from April 2009

• Improved performance at hotel operations in Atlantic Canada, driven by increased RevPAR as discussed above

Unfavourable

• The same factors as for the quarter discussed above

CORPORATE AND OTHER ⁽¹⁾

Financial Highlights (Unaudited)
Periods Ended December 31	Quarter						Annual
($ millions)	2010		2009		Variance		2010		2009		Variance
Revenue	7		6		1		30		27		3
Operating Expenses	3		5		(2	)	16		14		2
Amortization	2		1		1		7		8		(1	)
Finance Charges (2)	16		20		(4	)	73		79		(6	)
Corporate Tax Recovery	(3	)	(6	)	3		(16	)	(21	)	5
	(11	)	(14	)	3		(50	)	(53	)	3
Preference Share Dividends	7		5		2		28		18		10
Net Corporate and Other Expenses	(18	)	(19	)	1		(78	)	(71	)	(7	)

(1) Includes Fortis net corporate expenses, net expenses of non-regulated Terasen corporate-related activities and the financial results of Terasen's 30% ownership interest in CWLP and of Terasen's non-regulated wholly owned subsidiary TES

(2) Includes dividends on preference shares classified as long-term liabilities

Factors Contributing to Net Corporate and Other Expenses Variance

Quarter over Quarter

Favourable

• Lower finance charges, due to the finalization of capitalized interest, incurred to finance the Vaca hydroelectric generating facility during the period of construction, and the repayment of higher interest-bearing debt in 2010. The decrease was partially offset by the impact of higher average credit facility borrowings. In October 2010 Fortis redeemed its $100 million 7.4% unsecured debentures and in April 2010 Terasen redeemed its $125 million 8.0% Capital Securities with proceeds from borrowings under the Corporation's committed credit facility.

• Increased revenue, due to interest income on higher inter-company lending at higher interest rates to Fortis Properties to finance the Company's maturing external debt

• Lower operating expenses associated with differences in the timing of recovery of operating expenses from subsidiary companies

Unfavourable

• Higher preference share dividends, due to the issuance of First Preference Shares, Series H in January 2010

Factors Contributing to Net Corporate and Other Expenses Variance

Year over Year

Unfavourable

• Higher preference share dividends, for the same reason as for the quarter discussed above

• Higher operating expenses, primarily due to business development costs incurred in 2010, partially offset by higher recovery of costs from subsidiary companies and lower non-regulated operating expenses at Terasen Energy Services Inc.

Favourable

• Lower finance charges, excluding the impact of foreign exchange, for the same reasons as for the quarter discussed above. The decrease was partially offset by interest expense on the 30-year $200 million 6.51% unsecured debentures issued in July 2009 and the impact of higher average credit facility borrowings

• A favourable foreign exchange impact of approximately $2.5 million associated with the translation of US dollar-denominated interest expense, due to the weakening of the US dollar relative to the Canadian dollar

• Increased revenue, for the same reason as for the quarter discussed above

In December 2010 Fortis issued 10-year US$125 million 3.53% and 30-year US$75 million 5.26% unsecured notes. The net proceeds of the private note offerings were used to repay committed credit facility borrowings that were incurred to repay the Corporation's $100 million 7.4% unsecured debentures that matured in October 2010 and for general corporate purposes.

REGULATORY HIGHLIGHTS

The following is an update on material regulatory decisions and applications associated with each of the Corporation's regulated gas and electric utilities for the fourth quarter of 2010:

Material Regulatory Decisions and Applications
Regulated Utility	Summary Description
TGI/TGVI/TGWI	- TGI and TGVI review with the British Columbia Utilities Commission ("BCUC") natural gas and propane commodity rates and mid-stream rates every three months in order to ensure the flow-through rates charged to customers are sufficient to cover the cost of purchasing natural gas and propane and contracting for mid-stream resources, such as third-party pipeline or storage capacity. The commodity cost of natural gas and propane and mid-stream costs are flowed through to customers without markup. In December 2010 TGI filed an application with the BCUC to provide fuelling services through TGI-owned and operated compressed natural gas and liquefied natural gas ("LNG") fuelling stations. If the application is approved, commercial customers will be able to safely and economically refuel their fleet vehicles on their own premises, at rates regulated by the BCUC, using stations provided by TGI. - In December 2010 TGI received approval from the BCUC for a new renewable natural gas program for an initial two-year period. In 2011 up to 24,000 residential customers will be able to subscribe to the program, paying an approximate $4 monthly premium to replace 10% of their natural gas supply with biomethane. The BCUC approval also allows TGI to implement agreements with Catalyst Power Inc. and the Columbia Shuswap Regional District to collect biogas from agricultural waste and a landfill site, respectively. - In December 2010 the Terasen Gas companies filed a report with the BCUC, as required, which included a study by an external consultant, engaged by the utilities, of alternative formulaic ROE automatic adjustment mechanisms used in North America. Based on the study, the Terasen Gas companies are not proposing to adopt a formulaic ROE automatic adjustment mechanism at this time. - TGI, TGVI and TGWI are considering an amalgamation of the three companies. An amalgamation would require an application to be approved by the BCUC and consent of the Government of British Columbia. While a decision to proceed with an amalgamation has not yet been made, the Terasen Gas companies are contemplating bringing forth an application during 2011. - In January 2011 TGI filed its review of the Price Risk Management Plan ("PRMP") objectives with the BCUC related to its gas commodity hedging plan and also submitted a 2011-2014 PRMP. An updated PRMP for TGVI is expected to be filed by April 2011.
FortisBC	- In November 2010 FortisBC received Board of Directors' approval to enter into the Waneta Expansion Capacity Agreement to purchase capacity output from the 335-MW Waneta Expansion hydroelectric generating facility. The Waneta Expansion Capacity Agreement, which was accepted by the BCUC in September 2010, will allow FortisBC to purchase capacity for 40 years upon completion of the Waneta Expansion, which is anticipated in spring 2015. For further information, refer to the "Capital Program" section of this media release. - In December 2010 the BCUC approved an NSA pertaining to FortisBC's 2011 Revenue Requirements Application. The result was a general customer electricity rate increase of 6.6%, effective January 1, 2011. The rate increase was primarily the result of the Company's ongoing investment in electrical infrastructure and the higher cost of capital. Customer rates for 2011 reflect an allowed ROE of 9.90%, unchanged from 2010.  - In December 2010 FortisBC received BCUC approval of its 2011 Capital Expenditure Plan. Forecast capital expenditures for 2011 total approximately $99 million.
FortisAlberta	- In October 2010 the Central Alberta Rural Electrification Association ("CAREA") filed an application with the Alberta Utilities Commission ("AUC") requesting that CAREA be entitled to serve any new customer in the overlapping CAREA service area wishing to obtain electricity for use on property, and that FortisAlberta be restricted to, and shall provide, electricity distribution service in CAREA's service area only to a customer in that service area who is not being provided service by CAREA. FortisAlberta has intervened in the proceeding.
	- In December 2010 the AUC issued its decision on FortisAlberta's August 2010 Compliance Filing, which incorporated the AUC's decision, received in July 2010, on the Company's 2010 and 2011 Distribution Tariff Application ("DTA").  The December 2010 decision approved the Company's distribution revenue requirements of $346 million for 2010 and $368 million for 2011. New final distribution electricity rates and rate riders were also approved, effective January 1, 2011. - In its 2010 and 2011 DTA, FortisAlberta had requested an update in the forecast capital cost of its Automated Meter Infrastructure ("AMI") Project, bringing the total forecast project cost to $126 million (excluding the $15 million cost of the pilot program), up from an original total forecast project cost of $104 million.  The AUC reached the conclusion, however, that the capital cost of the AMI Project of $104 million (excluding the pilot program) had formed part of the Company's 2008 and 2009 NSA that had been approved in 2008 and, therefore, did not approve the updated forecast.  The Company filed a Review and Variance Application with the AUC and a Leave to Appeal with the Alberta Court of Appeal regarding this conclusion.  The AUC issued its decision regarding the Review and Variance Application approving a hearing into the prudency of the capital expenditures above $104 million.  A proceeding has been initiated and will be in writing with a decision expected in the second quarter of 2011.  The Company's Leave to Appeal has been adjourned pending the determination of the Review and Variance.  The Utilities Consumer Advocate filed with the Alberta Court of Appeal a Leave to Appeal request which has similarly been adjourned. - The AUC issued a Notice of Commission-Initiated Proceeding in December 2010 to finalize the allowed ROE for 2011, review capital structure and consider whether a return to a formula-based approach for annually setting the allowed ROE, beginning in 2012, is warranted.  In the absence of a formula-based approach, the AUC is expected to consider how the allowed ROE will be set for 2012.  This proceeding will also consider additional matters associated with customer contributions. - The AUC has initiated a process to reform utility rate regulation in Alberta.  The AUC has expressed its intention to apply a PBR formula to distribution service electricity rates.  FortisAlberta is currently assessing PBR and will participate fully in the AUC process.  The Company will submit a 2012 and 2013 Cost of Service ("COS") Application in the first quarter of 2011 under the Uniform System of Accounts/Minimum Filing Requirements format in order to bridge the transition between COS and possible PBR regulation.
Newfoundland Power	- In November 2010 the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") approved Newfoundland Power's application to defer the recovery of expected increased costs of $2.4 million, due to expiring regulatory amortizations, in 2011.  - In November 2010 the PUB approved Newfoundland Power's 2011 Capital Budget Plan totaling approximately $73 million, before customer contributions. - In accordance with the operation of the ROE automatic adjustment formula, Newfoundland Power's allowed ROE has been reduced from 9.00% for 2010 to 8.38% for 2011. - In December 2010 the PUB approved Newfoundland Power's application to: (i) adopt the accrual method of accounting for other post-employment benefit ("OPEB") costs, effective January 1, 2011; (ii) recover the transitional regulatory asset balance of approximately $53 million, associated with adoption of accrual accounting, over a 15-year period; and (iii) adopt an OPEB cost-variance deferral account to capture differences between OPEB expense calculated in accordance with Canadian GAAP and OPEB expense approved by the PUB for rate-setting purposes. - In December 2010 Newfoundland Power received approval from the PUB for an overall average 0.8% increase in customer electricity rates, effective January 1, 2011, resulting from the PUB's approval for the Company to change its accounting practices for OPEB costs, as described above, partially offset by the impact of the decrease in the allowed ROE for 2011.  - In December 2010 Newfoundland Power and Bell Aliant signed a new Support Structure Agreement, effective January 1, 2011, whereby Bell Aliant will buy back 40% of all joint-use poles and related infrastructure owned by Newfoundland Power for approximately $46 million.  This transaction represents approximately 5% of Newfoundland Power's rate base.  In 2001 Newfoundland Power purchased joint-use poles and related infrastructure from Bell Aliant (formerly Aliant Telecom Inc.) under a 10-year Joint-Use Facilities Partnership Agreement ("JUFPA") that expired December 31, 2010. Bell Aliant has rented space on these poles from Newfoundland Power since 2001 with the right to repurchase 40% of all joint-use poles at the end of the term. Bell Aliant exercised the option to buy back these poles from Newfoundland Power. The Support Structure Agreement is subject to certain conditions, including PUB approval of the sale of 40% of the Company's joint-use poles, which must be met by both parties by June 30, 2011, or either party may choose to terminate.  In the event of termination, the rights and recourses under the JUFPA will remain in effect for both parties. Newfoundland Power has filed an application with the PUB requesting approval of the transaction and expects the transaction to close in 2011.
	- As at December 31, 2010 Newfoundland Power recorded assets held for sale in the amount of approximately $45 million, which represented the estimated sales price less cost to sell the joint-use poles.  The estimated sales price will be adjusted upon completion of a pole survey in 2011. Effective January 1, 2011, the Company will no longer be receiving pole rental revenue from Bell Aliant. However, Newfoundland Power will be responsible for the construction and maintenance of Bell Aliant's support structure requirements throughout 2011. The Support Structure Agreement with Bell Aliant is not expected to materially impact Newfoundland Power's ability to earn a reasonable rate of return on its rate base in 2011. Newfoundland Power is currently working with Bell Aliant regarding the future operational and financial aspects of this transaction beyond 2011. The Company anticipates the proceeds from this transaction will be used to pay down its credit facility borrowings and maintain its equity component at 45%. - The Company is currently assessing the requirement for it to file an application with the PUB to recover expected increased costs in 2012.
Maritime Electric	- In November 2010 Maritime Electric entered into a power purchase agreement with New Brunswick Power ("NB Power") for a five-year period commencing March 2011, which will result in lower and stable power purchase costs for customers over the period.  - In November 2010 Maritime Electric signed the Prince Edward Island Energy Accord (the "Accord") with the Government of PEI.  The Accord covers the period from March 1, 2011 through February 29, 2016.  Under the terms of the Accord, the Government of PEI will assume responsibility for the cost of replacement energy and the monthly operating and maintenance costs related to the NB Power Point Lepreau Nuclear Generating Station ("Point Lepreau"), effective March 1, 2011 until Point Lepreau is fully refurbished, which is expected in fall 2012.  The Government of PEI will finance these costs, which are expected to be recovered from customers over a 25-year period beginning when Point Lepreau returns to service.  In the event that Point Lepreau does not return to service by fall 2012, the Government of PEI reserves the right to cease the monthly payments.  As permitted by the Island Regulatory and Appeals Commission, replacement energy costs incurred during the refurbishment period are being deferred by Maritime Electric and are expected to total approximately $47 million to the end of February 2011.  The nature and timing of the recovery of the deferred costs is subject to further review by a commission to be established by the Government of PEI.  The Accord also provides for the financing by the Government of PEI of costs associated with Maritime Electric's termination of the Dalhousie Unit Participation Agreement.  The costs will be subsequently collected from customers over a period to be established by the Government of PEI.  As a result of the Accord, customer electricity rates will decrease by approximately 14.0% effective March 1, 2011, at which time there will commence a two-year customer rate freeze.  - In December 2010 Maritime Electric received regulatory approval, as filed, of its 2011 Capital Budget totaling approximately $23 million, before customer contributions.
FortisOntario	- In November 2010 FortisOntario filed Third-Generation Incentive Rate Mechanism ("IRM") electricity distribution rate applications for Fort Erie, Gananoque and Port Colborne for customer rates effective May 1, 2011.  The Ontario Energy Board ("OEB") will publish the applicable inflationary productivity factors in the first quarter of 2011.  Customer electricity rates for 2011 will reflect an allowed ROE of 8.01% on a deemed equity component of 40%. - FortisOntario intends to file a COS Application in April 2011 for harmonized electricity distribution rates in Fort Erie, Port Colborne and Gananoque, effective January 1, 2012, using a 2012 forward test year. - In November 2010 the OEB approved an NSA pertaining to Algoma Power's electricity distribution rate application for customer rates, effective December 1, 2010 through December 31, 2011, using a 2011 forward test year.  The rates reflect an approved allowed ROE of 9.85% on a deemed equity component of 40%.  The OEB approval resulted in a 2011 revenue requirement of $20 million, of which approximately $11 million will be recovered through the Rural and Remote Rate Protection ("RRRP") Program with the remainder to be recovered through increased customer rates and charges.  Through regulations relating to the RRRP Program, the average increase in the electricity delivery charge to customers, effective December 1, 2010, was 2.5%.  The overall impact of the OEB rate decision on an average customer's electricity bill was an increase of 3.8%, including rate riders and other charges. - The present form of Third-Generation IRM will not accommodate Algoma Power's customer rate structure and the RRRP Program; therefore, Algoma Power has agreed to consult with interveners to develop a form of incentive rate-making that may be used between rebasing periods.  Due to regulations in Ontario associated with the RRRP Program, customer electricity distribution rates at Algoma Power are tied to the average changes in rates of other electric utilities in Ontario.  Pending these consultations, Algoma Power will file for incentive rate-making for customer electricity distribution rates, effective January 1, 2012.
Belize Electricity	- The evidentiary portion of the trial of Belize Electricity's appeal of the PUC's June 2008 Final Decision was heard in October 2010 with closing arguments completed in December 2010.  A court decision on the matter is expected in the first quarter of 2011.
Caribbean Utilities	- In November 2010 Caribbean Utilities filed its 2011-2015 Capital Investment Plan ("CIP") totaling approximately US$219 million.  The 2011-2015 CIP was prepared upon the basis of the Company's application to the Electricity Regulatory Authority ("ERA") for a delay in any new generation installation until there is more certainty in growth forecasts.  In January 2011 the ERA provided general approval of the US$134 million of proposed non-generation installation expenditures in the CIP.  The remaining US$85 million of the CIP related to new generation installation, which would be subject to a competitive solicitation process.  The general approval of non-generation expenditures is subject to Caribbean Utilities providing additional information related to certain planned projects.  Final approval of the CIP is expected during the first quarter of 2011.
Fortis Turks and Caicos	- In September 2010 Fortis Turks and Caicos received draft proposals and terms of reference from the Governor of the Turks and Caicos Islands (the "Governor") to review the Company's Electricity Rate Review filing.  Management has acknowledged the Governor's proposed terms of reference and objectives, and has proposed that a jointly funded and identified outside independent consultant be engaged to conduct a review of the filing and current rate-setting mechanism and make recommendations regarding both.

CAPITAL STRUCTURE

The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40% equity, including preference shares, and 60% debt, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in the utility's customer rates. 

The consolidated capital structure of Fortis is presented in the following table.

Capital Structure (Unaudited)	As at December 31
	2010		2009
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease obligations (net of cash) (1)	5,914	58.4	5,830	60.2
Preference shares (2)	912	9.0	667	6.9
Common shareholders' equity	3,305	32.6	3,193	32.9
Total (3)	10,131	100.0	9,690	100.0

(1) Includes long-term debt and capital lease obligations, including current portion, and short-term borrowings, net of cash

(2) Includes preference shares classified as both long-term liabilities and equity

(3) Excludes amounts related to non-controlling interests

The change in the capital structure was driven by the issuance of $250 million preference shares in January 2010, and increased common shares outstanding reflecting the impact of the Corporation's dividend reinvestment and share purchase plans. Repayments of long-term debt, capital lease obligations and short-term borrowings during 2010 were partially offset by proceeds from the issuance of long-term debt and the preference shares.

Credit Ratings: The Corporation's credit ratings are as follows:

Standard & Poor's ("S&P")	A-(stable) (long-term corporate and unsecured debt credit rating)
DBRS	A(low) (unsecured debt credit rating)

In December 2010 S&P confirmed the Corporation's long-term corporate and unsecured debt credit rating of A-(stable) and in October 2010 DBRS upgraded the Corporation's unsecured debt credit rating to A(low) from BBB(high). The credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, management's commitment to maintaining low levels of debt at the holding company level and the significant reduction in external debt at Terasen, the Corporation's reasonable credit metrics, and the Corporation's demonstrated ability and continued focus of acquiring and integrating stable regulated utility businesses financed on a conservative basis.

CASH FLOW

Summary of Consolidated Cash Flows: The table below outlines the Corporation's consolidated sources and uses of cash for the three and 12 months ended December 31, 2010, as compared to the same periods in 2009, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows (Unaudited)
Periods Ended December 31		Quarter						Annual
($ millions)		2010		2009		Variance		2010		2009		Variance
Cash, Beginning of Period		64		106		(42	)	85		66		19
Cash Provided by (Used in):
	Operating Activities	201		71		130		783		637		146
	Investing Activities	(333	)	(312	)	(21	)	(991	)	(1,045	)	54
	Financing Activities	177		221		(44	)	232		431		(199	)
	Effect of Exchange Rate Changes on Cash and Cash Equivalents	-		(1	)	1		-		(4	)	4
Cash, End of Period		109		85		24		109		85		24

Operating Activities:  Cash flow from operating activities, after working capital adjustments, was $130 million higher quarter over quarter. The increase was mainly due to: (i) higher earnings; (ii) the collection from customers of increased amortization costs, mainly at the Terasen Gas companies, as approved by the regulators; (iii) favourable working capital changes at the Terasen Gas companies, reflecting differences in the commodity cost of natural gas and the cost of natural gas charged to customers quarter over quarter and the effects of seasonality; (iv) favourable changes in the Alberta Electric System Operator ("AESO") charges deferral account at FortisAlberta; and (v) the timing of the declaration of common share dividends for the first quarter of 2010. 

Annual cash flow from operating activities, after working capital adjustments, was $146 million higher than the previous year. The increase was driven by: (i) higher earnings; (ii) the collection from customers of increased amortization costs, mainly at the Terasen Gas companies, as approved by the regulators; (iii) favourable changes in the AESO charges deferral account at FortisAlberta; (iv) a decrease in the amount of corporate taxes paid at Newfoundland Power; and (v) the timing of the declaration of common share dividends for the first quarter of 2010. The increase was partially offset by unfavourable working capital changes at the Terasen Gas companies, due to differences in the commodity cost of natural gas and the cost of natural gas charged to customers year over year and the effects of seasonality.

Investing Activities: Cash used in investing activities was $21 million higher quarter over quarter, driven by higher gross capital expenditures due to the commencement of construction of the non-regulated Waneta Expansion late in 2010 and increased capital spending at FortisAlberta, partially offset by the acquisition of Algoma Power during the fourth quarter of 2009, higher proceeds from the sale of utility capital assets and higher contributions in aid of construction. 

Annual cash used in investing activities was $54 million lower than the previous year. The decrease related to higher proceeds from the sale of utility capital assets, increased contributions in aid of construction and the acquisition of Algoma Power and the Holiday Inn Select Windsor in 2009. The decrease was partially offset by higher gross capital expenditures related to the commencement of construction of the non-regulated Waneta Expansion late in 2010 and higher capital spending at FortisBC, partially offset by lower capital spending at FortisAlberta and at Caribbean Regulated Electric Utilities.

Financing Activities: Cash provided by financing activities was $44 million lower quarter over quarter, primarily due to the timing of the declaration of common share dividends for the first quarter of 2010 and a lower net increase in debt, partially offset by higher advances from non-controlling interests and higher proceeds from the issuance of common shares. 
Annual cash provided by financing activities was $199 million lower than the previous year. The decrease was due to the timing of the declaration of common share dividends for the first quarter of 2010, increased dividends per common share and a lower net increase in debt, partially offset by higher proceeds from the issuance of preference and common shares and higher advances from non-controlling interests. In January 2010 Fortis publicly issued $250 million Five-Year Fixed Rate Reset First Preference Shares, Series H.

CAPITAL PROGRAM

Capital investment in infrastructure is required to ensure continued and enhanced performance, reliability and safety of the gas and electricity systems and to meet customer growth. All costs considered to be maintenance and repairs are expensed as incurred. Costs related to replacements, upgrades and betterments of capital assets are capitalized as incurred. 

Gross consolidated capital expenditures for the year ended December 31, 2010 were $1,073 million. A breakdown of gross consolidated capital expenditures by segment for 2010 is provided in the following table.

Gross Consolidated Capital Expenditures (Unaudited) (1) Year Ended December 31, 2010 ($ millions)
Terasen Gas Compa- nies	Fortis Alberta (2)	Fortis BC	New- found- land Power	Other Regu- lated Elec- tric Utili- ties – Cana- dian	Total Regu- lated Utili- ties - Cana- dian	Regu- lated Elec- tric Utili- ties - Cari- bbean	Non- Regu- lated - Utility (3)	Fortis Proper- ties	Total
253	379	139	78	48	897	72	85	19	1,073

(1) Relates to cash payments to acquire or construct utility capital assets, income producing properties and intangible assets, as reflected in the consolidated statement of cash flows. Includes asset removal and site restoration expenditures, net of salvage proceeds, for those utilities where such expenditures are permissible in rate base in 2010. Excludes capitalized amortization and non-cash equity component of the allowance for funds used during construction.

(2) Includes payments made to AESO for investment in transmission capital projects

(3) Includes non-regulated generation and corporate capital expenditures

Gross consolidated capital expenditures of $1,073 million for 2010 were $25 million lower than $1,098 million forecast for 2010 as disclosed in the MD&A for the year ended December 31, 2009. Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts. A decrease in capital spending at the Terasen Gas companies largely due to: (i) a regulator-approved decrease in capitalized overhead costs; (ii) a shift in capital spending from 2010 to 2011 related to certain projects; and (iii) lower-than-forecast capital spending on alternative energy projects, combined with lower actual capital costs at FortisBC mainly due to prevailing market conditions coupled with a shift in capital spending from 2010 to 2011 for certain projects, was partially offset by increased capital spending at the Non-Regulated Generation segment associated with the commencement of construction of the non-regulated Waneta Expansion late in 2010.

An update on significant capital projects for 2010 from that disclosed in the MD&A as at December 31, 2009 is provided below.

During 2010 TGI's Fraser River South Bank South Arm Rehabilitation Project experienced difficulties with one of the directional drills and the project is expected to be in service in 2011, rather than in 2010 as originally expected. The project is expected to cost approximately $35 million, up from $27 million forecast as at December 31, 2009.

During 2010 FortisAlberta continued with the replacement of conventional customer meters with AMI technology. The capital cost of the AMI project is expected to be approximately $126 million (excluding $15 million for the pilot program). To the end of 2010, $115 million has been spent on this project. For further information related to this project, refer to the "Material Regulatory Decisions and Applications - FortisAlberta" section of this media release.

In May 2010 Fortis Turks and Caicos received delivery of one of two diesel-powered generating units that have a combined generating capacity of approximately 18 MW. The first unit came into service in January 2011. The delivery of the second unit is anticipated in February 2011.

In October 2010 the Corporation, in partnership with Columbia Power Corporation and Columbia Basin Trust ("CPC/CBT"), concluded definitive agreements to construct the 335-MW Waneta Expansion at an estimated cost of approximately $900 million. The facility is sited adjacent to the Waneta Dam and powerhouse facilities on the Pend d'Oreille River, south of Trail, British Columbia. CPC/CBT are both 100% owned corporations of the Government of British Columbia. Fortis owns a controlling 51% interest in the Waneta Expansion Limited Partnership and will operate and maintain the non-regulated investment when the Waneta Expansion comes into service, which is expected in spring 2015. SNC-Lavalin was awarded a contract for approximately $590 million to design and build the Waneta Expansion. Construction began in November 2010 and approximately $75 million was incurred on this capital project in 2010. The Waneta Expansion will be included in the Canal Plant Agreement and will receive fixed energy and capacity entitlements based upon long-term average water flows, thereby significantly reducing hydrologic risk associated with the project. The energy, approximately 630 GWh, (and associated capacity required to deliver such energy) for the Waneta Expansion will be sold to BC Hydro under a long-term energy purchase agreement which has been executed. The surplus capacity, equal to 234 MW on an average annual basis, will be sold to FortisBC under a long-term capacity purchase agreement, which was accepted by the BCUC in September 2010.

Over the next five years, consolidated gross capital expenditures are expected to approach $5.5 billion. Of the capital spending, approximately 63% is expected to be incurred at the Regulated Electric Utilities, driven by FortisAlberta and FortisBC. Approximately 20% and 17% is expected to be incurred at the Regulated Gas Utilities and at non-regulated operations, respectively. Capital expenditures at the Regulated Utilities are subject to regulatory approval. 

A breakdown of forecast gross consolidated capital expenditures for 2011 by segment is provided in the following table.

Forecast Gross Consolidated Capital Expenditures (Unaudited) (1) Year Ended December 31, 2011 ($ millions)
Terasen Gas Compa- nies	Fortis Alberta (2)	Fortis BC	New- found- land Power	Other Regu- lated Elec- tric Utili- ties - Cana- dian	Total Regu- lated Utili- ties - Cana- dian	Regu- lated Elec- tric Utili- ties - Carib- bean	Non- Regu- lated - Utility (3)	Fortis Proper- ties	Total
281	420	99	73	46	919	83	183	27	1,212

(1) Relates to forecast cash payments to acquire or construct utility capital assets, income producing properties and intangible assets, as would be reflected in the consolidated statement of cash flows. Includes forecast asset removal and site restoration expenditures, net of salvage proceeds, for those utilities where such expenditures are permissible in rate base in 2011. Excludes forecast capitalized amortization and non-cash equity component of the allowance for funds used during construction.

(2) Includes forecast payments to be made to AESO for investment in transmission capital projects

(3) Includes forecast non-regulated generation and corporate capital expenditures

Significant capital projects for 2011 include: (i) continuation of construction of the non-regulated Waneta Expansion; (ii) continued implementation of the new customer information system and related call centres at TGI; (iii) completion of construction of the LNG storage facility at TGVI; (iv) completion of the Fraser River South Bank South Arm Rehabilitation Project at TGI; (iv) completion of the implementation of AMI technology at FortisAlberta; and (v) completion of the Okanagan Transmission Reinforcement Project at FortisBC.

CREDIT FACILITIES

As at December 31, 2010 the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.1 billion, of which $1.4 billion was unused, including $435 million unused under the Corporation's $600 million committed revolving credit facility. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 25% of these facilities. Approximately $2.0 billion of the total credit facilities are committed facilities, most of which have maturities in 2012 and 2013.

The following table outlines the credit facilities of the Corporation and its subsidiaries.

Credit Facilities (Unaudited)								As at December 31
($ millions)		Corporate and Other		Regulated Utilities		Fortis Properties		2010		2009
Total credit facilities		645		1,451		13		2,109		2,153
Credit facilities utilized:
	Short-term borrowings	-		(351	)	(7	)	(358	)	(415	)
	Long-term debt (including current portion)	(165	)	(53	)	-		(218	)	(208	)
Letters of credit outstanding		(1	)	(122	)	(1	)	(124	)	(100	)
Credit facilities unused		479		925		5		1,409		1,430

FUTURE ACCOUNTING CHANGES

Adoption of New Accounting Standards: In February 2008 the Canadian Accounting Standards Board ("AcSB") confirmed that Canadian GAAP for publicly accountable enterprises would be replaced by International Financial Reporting Standards ("IFRS") for fiscal years beginning on or after January 1, 2011.

The Corporation commenced its IFRS Conversion Project in 2007 when it established a formal project governance structure, which included the Fortis Audit Committee, senior management and project teams from each of the Fortis subsidiaries. Overall project governance, management and support have been coordinated by Fortis, with an independent external advisor engaged to assist in the IFRS conversion. 

IFRS does not currently provide guidance with respect to accounting for rate-regulated activities. Over the past two to three years, the International Accounting Standards Board ("IASB") discussed and deliberated on the subject of accounting for rate-regulated activities, but failed to reach a conclusion on any of the associated technical issues. In September 2010 the IASB reconfirmed its earlier view that matters associated with rate-regulated accounting could not be resolved quickly. The IASB, therefore, decided to defer any further discussion on accounting for rate-regulated activities until public consultation on its future agenda is held, and views as to what form, if any, a future project might take to address accounting for the effects of rate-regulated activities are obtained. Without specific guidance on accounting for rate-regulated activities by the IASB, a transition to IFRS would likely result in the derecognition of some, or perhaps all, of the Corporation's regulatory assets and liabilities, and net earnings may, as a result, be subject to significant volatility under current application of IFRS.

The pace and outcome of the IASB's activities has put Canadian rate-regulated entities at a significant disadvantage in terms of their ability to adopt IFRS as of January 1, 2011. Accordingly, the AcSB has provided qualifying entities with an option to defer their changeover to IFRS by one year. The necessary amendments to the Canadian Institute of Chartered Accountants ("CICA") Handbook were published by the AcSB in October 2010.

While the Corporation's IFRS Conversion Project has proceeded as planned in preparation for the adoption of IFRS on January 1, 2011, Fortis and its rate-regulated subsidiaries qualify for the optional one-year deferral and, therefore, will continue to prepare their financial statements in accordance with Part V of the CICA Handbook for all interim and annual periods ending on or before December 31, 2011. 

Due to the continued uncertainty around the timing and adoption of a rate-regulated accounting standard by the IASB, Fortis has evaluated the option of adopting US generally accepted accounting principles ("US GAAP"), effective January 1, 2012. Canadian rules allow a reporting issuer to prepare and file its financial statements in accordance with US GAAP by qualifying as a US Securities and Exchange Commission ("SEC") Issuer. An SEC Issuer is defined under the Canadian rules as an issuer that: (i) has a class of securities registered with the US Securities and Exchange Commission under Section 12 of the US Securities Exchange Act of 1934, as amended (the "Exchange Act"); or (ii) is required to file reports under Section 15(d) of the Exchange Act. The Corporation has developed and initiated a plan to become an SEC Issuer by December 31, 2011. As an SEC Issuer, Fortis will then be permitted to prepare and file its consolidated financial statements in accordance with US GAAP. Barring a change that will provide certainty as to the Corporation's ability to recognize regulatory assets and liabilities under IFRS, Fortis expects to prepare its consolidated financial statements in accordance with US GAAP for all interim and annual periods beginning on or after January 1, 2012. Several other Canadian investor-owned rate-regulated utilities are also expected to take a similar approach to possible adoption of US GAAP in 2012.

The adoption of US GAAP in 2012 is expected to result in fewer significant changes in the Corporation's accounting policies as compared to those that may have resulted with the adoption of IFRS. The Corporation's application of Canadian GAAP currently relies on US GAAP for guidance on accounting for rate-regulated activities, which allows the economic impact of rate-regulated activities to be properly recognized in the financial statements in a manner consistent with the timing by which amounts are reflected in customer rates. Fortis believes that the continued application of rate-regulated accounting, and the associated recognition of regulatory assets and liabilities under US GAAP, more accurately reflects the impact that rate regulation has on the Corporation's consolidated financial position and results of operations. 

The Corporation's plan to adopt US GAAP effective January 1, 2012 consists of the following three phases:

Phase I - Scoping and Diagnostics: This phase consists of project initiation and awareness, identification of high-level differences between US GAAP and Canadian GAAP and project planning and resourcing. Work on Phase I commenced in the fourth quarter of 2010 and is scheduled for completion by mid-year 2011. 

Phase II - Analysis and Development: This phase consists of detailed diagnostics and evaluation of the financial impacts of adopting US GAAP; identification and design of operational and financial business processes; and development of required solutions to address identified issues. Phase II of the plan commenced in January 2011 and is scheduled for completion by the third quarter of 2011.

Phase III - Implementation and Review: This phase involves implementation of the changes required by the Corporation to prepare and file its consolidated financial statements in accordance with US GAAP beginning in 2012 and communication of the associated impacts. Phase III will commence in the second quarter of 2011 and will conclude when the Corporation issues its first annual audited US GAAP consolidated financial statements for the year ending December 31, 2012. Commencing with the first quarter of 2012, the Corporation's unaudited interim consolidated financial statements will be prepared in accordance with US GAAP.

The Corporation's IFRS project advisors will continue to advise the Corporation on accounting related matters with respect to the adoption of US GAAP. Legal counsel has also been engaged to assist with securities' filings and other legal matters associated with the adoption of US GAAP.

OUTLOOK

The Corporation's significant capital program, which is expected to be approximately $1.2 billion in 2011 and approach $5.5 billion over the next five years, including work on the Waneta Expansion, should drive growth in earnings and dividends. 

The Corporation continues to pursue acquisitions for profitable growth, focusing on regulated electric and natural gas utilities in the United States and Canada. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy.

FORTIS INC.

Consolidated Financial Statements

For the three and 12 months ended December 31, 2010 and 2009

(Unaudited)

Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at December 31
(in millions of Canadian dollars)
	2010		2009
ASSETS
Current assets
Cash and cash equivalents	$109		$85
Accounts receivable	655		595
Prepaid expenses	17		16
Regulatory assets	241		221
Inventories	168		178
Future income taxes	14		29
	1,204		1,124
Assets held for sale	45		-
Other assets	168		174
Regulatory assets	831		726
Future income taxes	16		17
Utility capital assets	8,202		7,693
Income producing properties	560		559
Intangible assets	324		286
Goodwill	1,553		1,560
	$12,903		$12,139
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings	$358		$415
Accounts payable and accrued charges	953		852
Dividends payable	54		3
Income taxes payable	30		23
Regulatory liabilities	60		51
Current installments of long-term debt and capital lease obligations	56		224
Future income taxes	6		24
	1,517		1,592
Other liabilities	308		295
Regulatory liabilities	467		423
Future income taxes	623		570
Long-term debt and capital lease obligations	5,609		5,276
Preference shares	320		320
	8,844		8,476
Shareholders' equity
Common shares	2,578		2,497
Preference shares	592		347
Contributed surplus	12		11
Equity portion of convertible debentures	5		5
Accumulated other comprehensive loss	(94	)	(83	)
Retained earnings	804		763
	3,897		3,540
Non-controlling interests	162		123
	4,059		3,663
	$12,903		$12,139

Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars, except per share amounts)
		Quarter Ended		Year Ended
		2010	2009	2010	2009
Revenue		$1,036	$1,020	$3,664	$3,643
Expenses
	Energy supply costs	507	520	1,686	1,799
	Operating	228	213	828	779
	Amortization	103	91	410	364
		838	824	2,924	2,942
Operating income		198	196	740	701
Finance charges		85	92	350	360
Earnings before corporate taxes		113	104	390	341
Corporate taxes		19	15	67	49
Net earnings		$94	$89	$323	$292
Net earnings attributable to:
	Non-controlling interests	$2	$3	$10	$12
	Preference equity shareholders	7	5	28	18
	Common equity shareholders	85	81	285	262
		$94	$89	$323	$292
Earnings per common share
	Basic	$0.49	$0.48	$1.65	$1.54
	Diluted	$0.47	$0.46	$1.62	$1.51

Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
	Quarter Ended				Year Ended
	2010		2009		2010		2009
Balance at beginning of period	$770		$682		$763		$634
Net earnings attributable to common and preference equity shareholders	92		86		313		280
	862		768		1,076		914
Dividends on common shares	(51	)	-		(244	)	(133	)
Dividends on preference shares classified as equity	(7	)	(5	)	(28	)	(18	)
Balance at end of period	$804		$763		$804		$763

Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
		Quarter Ended				Year Ended
		2010		2009		2010		2009
Net earnings		$94		$89		$323		$292
Other comprehensive (loss) income
Unrealized foreign currency translation losses on net investments in self-sustaining foreign operations		(20	)	(11	)	(33	)	(90	)
Gains on hedges of net investments in self-sustaining foreign operations		17		8		25		67
Corporate tax expense		(3	)	(1	)	(4	)	(9	)
Unrealized foreign currency translation losses, net of hedging activities and tax		(6	)	(4	)	(12	)	(32	)
Gain on derivative instruments designated as cash flow hedges, net of tax		-		-		-		1
Reclassification to earnings of net losses on derivative instruments previously discontinued as cash flow hedges, net of tax		-		-		1		-
Comprehensive income		$88		$85		$312		$261
Comprehensive income attributable to:
	Non-controlling interests	$2		$3		$10		$12
	Preference equity shareholders	7		5		28		18
	Common equity shareholders	79		77		274		231
		$88		$85		$312		$261

Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
			Quarter Ended				Year Ended
			2010		2009		2010		2009
Operating activities
	Net earnings		$94		$89		$323		$292
	Items not affecting cash:
		Amortization - utility capital assets and income producing properties	92		80		368		317
		Amortization - intangible assets	10		11		40		43
		Amortization - other	1		-		2		4
		Future income taxes	(2	)	(4	)	(3	)	5
		Other	1		-		(5	)	(8	)
	Change in long-term regulatory assets and liabilities		13		(5	)	9		25
			209		171		734		678
	Change in non-cash operating working capital		(8	)	(100	)	49		(41	)
			201		71		783		637
Investing activities
	Change in other assets and other liabilities		(1	)	3		-		(1	)
	Capital expenditures - utility capital assets		(336	)	(241	)	(1,008	)	(966	)
	Capital expenditures - income producing properties		(5	)	(11	)	(19	)	(26	)
	Capital expenditures - intangible assets		(29	)	(9	)	(46	)	(32	)
	Contributions in aid of construction		26		16		67		56
	Proceeds on sale of utility capital assets		12		-		15		1
	Business acquisitions		-		(70	)	-		(77	)
			(333	)	(312	)	(991	)	(1,045	)
Financing activities
	Change in short-term borrowings		(52	)	79		(56	)	8
	Proceeds from long-term debt, net of issue costs		523		119		523		729
	Repayments of long-term debt and capital lease obligations		(114	)	(24	)	(329	)	(172	)
	Net (repayments) borrowings under committed credit facilities		(185	)	40		8		(14	)
	Advances from (to) non-controlling interests		44		-		45		(5	)
	Issue of common shares, net of costs		22		14		80		46
	Issue of preference shares, net of costs		-		-		242		-
	Dividends
		Common shares	(51	)	-		(244	)	(133	)
		Preference shares	(7	)	(5	)	(28	)	(18	)
		Subsidiary dividends paid to non-controlling interests	(3	)	(2	)	(9	)	(10	)
			177		221		232		431
Effect of exchange rate changes on cash and cash equivalents			-		(1	)	-		(4	)
Change in cash and cash equivalents			45		(21	)	24		19
Cash and cash equivalents, beginning of period			64		106		85		66
Cash and cash equivalents, end of period			$109		$85		$109		$85

SEGMENTED INFORMATION (Unaudited)

Information by reportable segment is as follows:

	REGULATED									NON-REGULATED
	Gas Utilities	Electric Utilities
Quarter Ended December 31, 2010 ($ millions)	Terasen Gas Companies -Canadian	Fortis Alberta		Fortis BC	NF Power	Other Cana-dian(1)		Total Electric Canadian	Elec- tric Carib- bean	Fortis Generation (2)		Fortis Properties	Corporate and Other		Inter-segment eliminations		Consolidated
Revenue	480	99		73	152	87		411	84	9		57	7		(12	)	1,036
Energy supply costs	277	-		23	102	59		184	51	-		-	-		(5	)	507
Operating expenses	87	37		21	15	12		85	13	2		38	3		-		228
Amortization	27	32		10	12	5		59	9	1		5	2		-		103
Operating income	89	30		19	23	11		83	11	6		14	2		(7	)	198
Finance charges	29	14		8	9	5		36	5	-		6	16		(7	)	85
Corporate tax expense (recovery)	15	(1	)	1	4	1		5	-	1		1	(3	)	-		19
Net earnings (loss)	45	17		10	10	5		42	6	5		7	(11	)	-		94
Non-controlling interests	-	-		-	1	-		1	1	-		-	-		-		2
Preference share dividends	-	-		-	-	-		-	-	-		-	7		-		7
Net earnings (loss) attributable to common equity shareholders	45	17		10	9	5		41	5	5		7	(18	)	-		85
Goodwill	908	227		221	-	63		511	134	-		-	-		-		1,553
Identifiable assets	4,319	2,144		1,263	1,191	646		5,244	779	324		576	505		(397	)	11,350
Total assets	5,227	2,371		1,484	1,191	709		5,755	913	324		576	505		(397	)	12,903
Gross capital expenditures (3)	71	121		40	22	15		198	19	77		5	-		-		370
Quarter Ended
December 31, 2009
($ millions)
Revenue	497	86		69	146	79		380	85	5		54	6		(7	)	1,020
Energy supply costs	300	-		22	99	50		171	50	-		-	-		(1	)	520
Operating expenses	79	34		20	13	12		79	13	2		37	5		(2	)	213
Amortization	26	24		9	12	5		50	8	1		5	1		-		91
Operating income	92	28		18	22	12		80	14	2		12	-		(4	)	196
Finance charges	30	14		8	9	6		37	4	-		5	20		(4	)	92
Corporate tax expense (recovery)	14	(1	)	2	4	(1	)	4	-	1		2	(6	)	-		15
Net earnings (loss)	48	15		8	9	7		39	10	1		5	(14	)	-		89
Non-controlling interests	-	-		-	1	-		1	3	(1	)	-	-		-		3
Preference share dividends	-	-		-	-	-		-	-	-		-	5		-		5
Net earnings (loss) attributable to common equity shareholders	48	15		8	8	7		38	7	2		5	(19	)	-		81
Goodwill	908	227		221	-	63		511	141	-		-	-		-		1,560
Identifiable assets	4,086	1,892		1,141	1,165	618		4,816	799	200		576	491		(389	)	10,579
Total assets	4,994	2,119		1,362	1,165	681		5,327	940	200		576	491		(389	)	12,139
Gross capital expenditures (3)	70	92		36	22	13		163	15	-		10	3		-		261

(1)	Includes Algoma Power from October 2009, the date of acquisition by FortisOntario
(2)	Results reflect contribution from the Vaca hydroelectric generating facility in Belize which was commissioned in March 2010.
(3)	Relates to cash payments to acquire or construct utility capital assets, including amounts for AESO transmision capital projects, income producing properties and intangible assets, as reflected in the consolidated statement of cash flows

	REGULATED								NON-REGULATED
	Gas Utilities	Electric Utilities
Annual December 31, 2010 ($ millions)	Terasen Gas Companies - Canadian	Fortis Alberta		Fortis BC	NF Power	Other Cana- dian (1)	Total Electric Canadian	Elec- tric Carib- bean	Fortis Generation (2)	Fortis Properties	Corporate and Other		Inter- segment eliminations		Consolidated
Revenue	1,547	388		266	555	331	1,540	335	36	226	30		(50	)	3,664
Energy supply costs	863	-		73	358	215	646	201	1	-	-		(25	)	1,686
Operating expenses	288	141		73	62	45	321	48	9	151	16		(5	)	828
Amortization	108	126		41	47	23	237	36	4	18	7		-		410
Operating income	288	121		79	88	48	336	50	22	57	7		(20	)	740
Finance charges	113	54		32	36	21	143	17	-	24	73		(20	)	350
Corporate tax expense (recovery)	45	(1	)	5	16	8	28	1	2	7	(16	)	-		67
Net earnings (loss)	130	68		42	36	19	165	32	20	26	(50	)	-		323
Non-controlling interests	-	-		-	1	-	1	9	-	-	-		-		10
Preference share dividends	-	-		-	-	-	-	-	-	-	28		-		28
Net earnings (loss) attributable to common equity shareholders	130	68		42	35	19	164	23	20	26	(78	)	-		285
Goodwill	908	227		221	-	63	511	134	-	-	-		-		1,553
Identifiable assets	4,319	2,144		1,263	1,191	646	5,244	779	324	576	505		(397	)	11,350
Total assets	5,227	2,371		1,484	1,191	709	5,755	913	324	576	505		(397	)	12,903
Gross capital expenditures (3)	253	379		139	78	48	644	72	84	19	1		-		1,073
Annual
December 31, 2009
($ millions)
Revenue	1,663	331		253	527	285	1,396	339	39	219	27		(40	)	3,643
Energy supply costs	1,022	-		72	346	183	601	192	2	-	-		(18	)	1,799
Operating expenses	268	132		70	52	38	292	54	11	146	14		(6	)	779
Amortization	102	94		37	45	19	195	37	5	17	8		-		364
Operating income	271	105		74	84	45	308	56	21	56	5		(16	)	701
Finance charges	121	50		32	35	19	136	16	2	22	79		(16	)	360
Corporate tax expense (recovery)	33	(5	)	5	16	6	22	2	3	10	(21	)	-		49
Net earnings (loss)	117	60		37	33	20	150	38	16	24	(53	)	-		292
Non-controlling interests	-	-		-	1	-	1	11	-	-	-		-		12
Preference share dividends	-	-		-	-	-	-	-	-	-	18		-		18
Net earnings (loss) attributable to common equity shareholders	117	60		37	32	20	149	27	16	24	(71	)	-		262
Goodwill	908	227		221	-	63	511	141	-	-	-		-		1,560
Identifiable assets	4,086	1,892		1,141	1,165	618	4,816	799	200	576	491		(389	)	10,579
Total assets	4,994	2,119		1,362	1,165	681	5,327	940	200	576	491		(389	)	12,139
Gross capital expenditures (3)	246	407		115	74	46	642	92	14	26	4		-		1,024

(1)	Includes Algoma Power from October 2009, the date of acquisition by FortisOntario
(2)	Results reflect the expiry, on April 30, 2009, at the end of a 100-year term, of the 75 MW of water-right entitlement associated with the Rankine hydroelectric generating facility at Niagara Falls. Results also reflect contribution from the Vaca hydroelectric generating facility in Belize which was commissioned in March 2010.
(3)	Relates to cash payments to acquire or construct utility capital assets, including amounts for AESO transmision capital projects, income producing properties and intangible assets, as reflected in the consolidated statement of cash flows

CORPORATE INFORMATION

Fortis Inc. is the largest investor-owned distribution utility in Canada. With total assets of $12.9 billion and fiscal 2010 revenue totalling approximately $3.7 billion, the Corporation serves approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State. It also owns and operates hotels and commercial office and retail space primarily in Atlantic Canada. Fortis Inc. shares are listed on the Toronto Stock Exchange and trade under the symbol FTS.

Share Transfer Agent and Registrar:

Computershare Trust Company of Canada

9th Floor, 100 University Avenue

Toronto, ON M5J 2Y1

T: 514.982.7555 or 1.866.586.7638

F: 416.263.9394 or 1.888.453.0330

W: www.computershare.com/fortisinc

Additional information, including the Fortis 2009 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's web site at www.fortisinc.com.