Fortis Inc.
TSX : FTS

Fortis Inc.

February 19, 2015 06:30 ET

Fortis Releases 2014 Annual Results

- Annual Dividend to Common Shareholders Raised for Record 42 Consecutive Years

- UNS Energy Acquisition Completed

- Capital Expenditure Program Reached Record $1.7 Billion

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - Feb. 19, 2015) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) released its 2014 annual results today. Net earnings attributable to common equity shareholders for 2014 were $317 million, or $1.41 per common share, compared to $353 million, or $1.74 per common share, for 2013. Excluding the impact of non-recurring items in 2014 and 2013, described further below, net earnings attributable to common equity shareholders for 2014 were $407 million, or $1.81 per common share, an increase of $63 million, or $0.11 per common share, from $344 million, or $1.70 per common share, for 2013.

In December 2014 Fortis increased its quarterly common share dividend to 34 cents from 32 cents, commencing with the first quarter dividend payable on March 1, 2015, which translates into an annualized dividend of $1.36. Fortis has raised its annualized dividend to common shareholders for 42 consecutive years, the record for a public corporation in Canada.

In August 2014 Fortis acquired UNS Energy Corporation ("UNS Energy") for US$60.25 per common share in cash, for a purchase price of approximately US$4.5 billion, including the assumption of approximately US$2.0 billion of debt. UNS Energy, headquartered in Tucson, Arizona, is engaged through its primary subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, and serves approximately 658,000 electricity and gas customers.

"The acquisition of UNS Energy in Arizona has transformed Fortis from the largest investor-owned distribution utility in Canada to a leader in electric and gas utilities in North America," says Barry Perry, President and Chief Executive Officer, Fortis. Fortis now has more than $26 billion of assets, with the acquisition of UNS Energy bolstering assets by approximately one-third. Fortis now owns nine utilities - five in Canada, two in the United States and two in the Caribbean - and serves more than three million electricity and gas customers.

Financing of the net cash purchase price of approximately $2.7 billion (US$2.5 billion) is substantially complete. Fortis completed the sale of $1.8 billion 4% convertible unsecured subordinated debentures, represented by installment receipts ("Convertible Debentures"). Proceeds from the initial installment of approximately $599 million were received in January 2014. Proceeds from the final installment of approximately $1.2 billion were received on October 28, 2014. Following the receipt of the final installment, approximately 58.2 million common shares of Fortis were issued on conversion of the debentures. In September 2014 Fortis issued 24 million 4.1% Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series M for gross proceeds of $600 million. The remainder of the purchase price was financed through credit facility borrowings.

"Our annual consolidated capital program reached a record $1.7 billion in 2014, almost 50% higher than 2013," says Perry. "Our Waneta Expansion is progressing well and UNS Energy completed the purchase of the 550-megawatt Gila River plant in the fourth quarter, as expected."

Construction of the $900 million, 335-megawatt ("MW") Waneta Expansion hydroelectric generating facility ("Waneta Expansion") in British Columbia continues on time and on budget, with completion of the facility expected in spring 2015. Approximately $679 million has been invested in the Waneta Expansion since construction began in late 2010. In October 2014 FortisBC started construction of its $400 million Tilbury liquefied natural gas ("LNG") facility expansion in British Columbia, which will include a second LNG tank and a new liquefier, both to be in service by the end of 2016. The Tilbury expansion will be included in regulated rate base. In December 2014 UNS Energy purchased the 550-MW Unit 3 Gila River combined cycle gas-fired generating station for $252 million (US$219 million). Gila River strengthens the Company's generation portfolio and reduces its reliance on coal-based generation.

Results for both years were impacted by non-recurring items, largely associated with the acquisition of UNS Energy in 2014 and Central Hudson Gas & Electric Corporation ("Central Hudson") in 2013. Earnings for 2014 were reduced by $39 million, or $0.17 per common share, due to acquisition-related expenses and customer benefits offered to obtain regulatory approval of the acquisition of UNS Energy, compared to $34 million, or $0.17 per common share, associated with the acquisition of Central Hudson in 2013. Interest expense of $51 million after tax, including a make-whole payment, or $0.23 per common share, associated with the Convertible Debentures issued to finance a portion of the acquisition of UNS Energy was recognized in 2014. In addition, earnings for 2013 were favourably impacted by an income tax recovery of $23 million, or $0.11 per common share, due to the enactment of higher deductions associated with Part VI.1 tax on the Corporation's preference share dividends, and an extraordinary gain of $20 million, or $0.10 per common share, related to the settlement of expropriation matters associated with the Exploits River Hydro Partnership ("Exploits Partnership").

"Regulated Utilities performed well during the year," says Perry. "The UNS Energy acquisition closed in just eight months and contributed significantly during the year. Excluding one-time acquisition-related expenses, the acquisition of UNS Energy was immediately accretive to earnings per common share."

Regulated Utilities contributed earnings of $460 million compared to $392 million for 2013. The increase was driven by $60 million of earnings at UNS Energy from the date of acquisition and the first full year of earnings contribution from Central Hudson, which was acquired in June 2013. FortisAlberta's earnings were $9 million higher year over year, driven by rate base growth and an increase in the number of customers. Earnings at Caribbean Regulated Electric Utilities were $4 million higher than 2013, driven by electricity sales growth. The increases were partially offset by lower earnings at Eastern Canadian Electric Utilities, due to income tax recoveries of approximately $17 million in 2013 associated with Part VI.1 tax, and at FortisBC Electric, primarily due to the impact of lower-than-expected finance charges in 2013. Earnings at the FortisBC Energy companies were comparable with 2013.

"The regulatory calendar was extensive again in 2014 and significant regulatory processes are ongoing in Alberta and New York," says Perry. "A focus across the organization has been one of maintaining trust and credibility with our regulators by filing high-quality applications that are transparent and comprehensive," he adds.

A decision on multi-year performance-based rate-setting applications in British Columbia was received in September 2014 and did not have a material impact on earnings for 2014. A generic cost of capital proceeding is continuing in Alberta and the outcome is expected in the first quarter of 2015. A hearing related to FortisAlberta's combined capital tracker application for 2013 through 2015, which is an application for revenue increases related to its capital expenditure program, was held in October 2014. In 2013 and 2014, FortisAlberta recognized capital tracker revenue based on the interim regulatory decision granting 60% of the applied for capital tracker amounts. In December 2014 an interim decision was received granting FortisAlberta 90% of the applied for capital tracker amounts for 2015. A final decision on the combined capital tracker application is expected in the first quarter of 2015. In July 2014 Central Hudson filed a general rate application to establish rates effective July 1, 2015. A Joint Settlement Proposal was filed in February 2015 that provides for new rates at Central Hudson for a three-year period beginning July 1, 2015, reflecting an allowed rate of return on common shareholders' equity of 9.0% and a 48% common equity component of capital structure. Public statement hearings are expected to be held in March or April with the Joint Settlement Proposal targeted to go to the regulator in June for consideration and approval.

Non-Regulated Fortis Generation contributed $20 million to earnings compared to $39 million for 2013. The decrease was primarily due to the recognition of an approximate $20 million after-tax extraordinary gain on the settlement of expropriation matters associated with the Exploits Partnership in 2013.

Non-Utility operations contributed earnings of $28 million, an increase of $10 million from 2013. Earnings for 2014 included $5 million associated with Griffith Energy Services, Inc. ("Griffith") compared to a loss of $5 million for 2013. Griffith was acquired as part of the acquisition of Central Hudson in June 2013 and was sold in March 2014 for proceeds of approximately $105 million (US$95 million). Earnings at Fortis Properties of $23 million were comparable with 2013. In September 2014 the Corporation announced that it would engage in a review of strategic options for its hotel and commercial real estate business, operating as Fortis Properties. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering.

"The strategic review of Fortis Properties continues and we expect to make a decision on the future of this business in the second quarter of 2015," says Perry.

Corporate and Other expenses were $33 million higher year over year, excluding the impacts of interest expense on the Convertible Debentures, acquisition-related expenses and income tax recoveries of approximately $6 million associated with Part VI.1 tax in 2013. The increase was primarily due to higher finance charges, largely due to the acquisitions of UNS Energy and Central Hudson, and higher operating expenses. The increase in operating expenses was mainly due to employee-related expenses, including approximately $11 million in one-time after-tax retirement expenses; share-based compensation expenses, as a result of share price appreciation; higher legal and consulting fees; and general inflationary increases. The increase in Corporate and Other expenses was partially offset by an $8 million foreign exchange gain compared to $6 million in 2013, a higher income tax recovery and interest income.

Cash flow from operating activities was $982 million for 2014, an increase of $83 million from 2013. The increase was driven by higher cash earnings, partially offset by unfavourable changes in working capital and long-term regulatory deferrals.

Earnings for the fourth quarter were $113 million, or $0.44 per common share, compared to $100 million, or $0.47 per common share, for the same quarter in 2013. The increase in earnings for the quarter was primarily due to: (i) earnings contribution of $23 million from UNS Energy; (ii) higher earnings at FortisAlberta, driven by customer growth and the timing of operating expenses; and (iii) higher earnings at the Non-Utility segment, due to higher contribution from Fortis Properties and the impact of a net loss of approximately $2.5 million at Griffith in the fourth quarter of 2013. The increase was partially offset by higher net Corporate and Other expenses and lower earnings at Central Hudson. The increase in net Corporate and Other expenses was primarily due to higher finance charges and preference share dividends associated with the financing of the acquisition of UNS Energy, and approximately $4 million in after-tax interest expense associated with the Convertible Debentures, partially offset by a higher income tax recovery. At Central Hudson, the continued impact of higher depreciation and operating expenses during the two-year rate freeze post acquisition had an unfavourable impact on earnings. Higher storm-restoration and other non-recurring expenses also reduced Central Hudson's earnings in the fourth quarter of 2014. The decrease in earnings per common share was due to the impact of an increase in the weighted average number of common shares outstanding due to the issuance of 58.2 million common shares in October 2014 upon conversion of the Convertible Debentures issued to finance a portion of the acquisition of UNS Energy.

Fortis is one of the highest-rated utility holding companies in North America, with its corporate debt rated A- by Standard & Poor's ("S&P") and A(low) by DBRS. In October 2014, following the completion of equity financing associated with the acquisition of UNS Energy, S&P confirmed the Corporation's credit rating and revised its outlook to Stable. Similarly, in December 2014 DBRS confirmed the Corporation's credit rating with a Stable outlook.

"The capital markets have shown confidence in Fortis, as evidenced by the successful large financings we completed during the year," says Perry. "In addition to the $1.8 billion common equity and $600 million preference share issues associated with the UNS Energy acquisition, Fortis and its utilities raised more than $1 billion in long-term debt in 2014 at attractive interest rates."

In June and September, Fortis issued a total of US$500 million in senior unsecured notes, with terms to maturity ranging from 5 to 30 years and coupon rates ranging from 2.92% to 5.03%. The net proceeds were used to repay US-dollar denominated borrowings on the Corporation's credit facility, to refinance existing indebtedness, including the US$150 million 5.74% senior unsecured notes of Fortis that matured in October and $125 million 5.56% unsecured debentures of a subsidiary that matured in September, and for general corporate purposes. In September FortisAlberta issued $275 million unsecured debentures in two tranches, comprised of 10-year $150 million unsecured debentures at 3.30% and 30-year $125 million unsecured debentures at 4.11%. Net proceeds were used to repay $200 million 5.33% unsecured debentures that matured in October, to finance capital expenditures and for general corporate purposes. In October FortisBC Electric issued 30-year $200 million unsecured debentures at 4.00%. Net proceeds were used to repay existing indebtedness, including $140 million 5.48% unsecured debentures that matured in November. Long-term debt offerings were also completed at Central Hudson and Caribbean Regulated Electric Utilities.

"This is a very exciting time for Fortis. Following a decade of significant growth, mainly resulting from acquisitions, Fortis is entering a period of significant growth from our existing operations. Our consolidated capital program, which is designed to ensure we continue to meet the energy needs of our customers, is expected to exceed $2.0 billion in 2015. Over the five-year period through 2019, it is expected to approach $9 billion," says Perry.

"Over the next five years, total investment in energy infrastructure is expected to increase midyear rate base by approximately 36% from $14 billion in 2014 to approximately $19 billion in 2019. This capital investment should allow rate base to increase at a five-year compound annual growth rate of approximately 6.5% through 2019," he explains.

"Fortis is also pursuing significant natural gas investment opportunities, particularly in British Columbia. Two new regulated projects - a further expansion of the Tilbury LNG facility and the Woodfibre pipeline expansion, could increase the five-year compound annual growth rate through 2019 to 7.5%," concludes Perry.

Teleconference to Discuss 2014 Annual Results

A teleconference and webcast will be held on February 19 at 10:00 a.m. (Eastern). Barry Perry, President and Chief Executive Officer, Fortis, and Karl Smith, Executive Vice President, Chief Financial Officer, Fortis, will discuss the Corporation's 2014 annual results.

Analysts, members of the media and other interested parties in North America are invited to participate by calling 1.877.223.4471. International participants may participate by calling 647.788.4922. Please dial in 10 minutes prior to the start of the call. No pass code is required.

A live and archived audio webcast of the teleconference will be available on the Corporation's website, www.fortisinc.com.

A replay of the conference will be available two hours after the conclusion of the call until March 1, 2015. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 44984280.

Management Discussion and Analysis
For the year ended December 31, 2014
Dated February 18, 2015

FORWARD-LOOKING INFORMATION

The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. The MD&A should be read in conjunction with the Audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2014. Financial information for 2014 and comparative periods contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") and is presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in the MD&A 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 based on information currently available.
The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the Corporation's review of strategic options for its hotel and commercial real estate business; the expectation that UNS Energy Corporation ("UNS Energy") is able to satisfy the requirements of its customer base and meet future peak demand requirements; the expectation that there will be a significant reduction in the use of coal in certain of UNS Energy's generating facilities by 2020; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation's forecast gross consolidated capital expenditures for 2015 and total capital spending over the five-year period from 2015 through 2019; the nature, timing and expected costs of certain capital projects including, without limitation, the Waneta Expansion hydroelectric generating facility, the Tilbury liquefied natural gas facility expansion, the Woodfibre pipeline expansion, the development of a diesel power plant in Grand Cayman, and the Pinal transmission project in Arizona; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of cash from operations, borrowings under credit facilities, equity injections from Fortis and long-term debt offerings; the expectation that the Corporation's subsidiaries will be able to source the cash required to fund their 2015 capital expenditure programs, operating and interest costs, and dividend payments; the expected consolidated long-term debt maturities and repayments in 2015 and on average annually over the next five years; the expectation that long-term debt will not be settled prior to maturity; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to capital in the near to long terms;
the expectation that the combination of available credit facilities and relatively low annual debt maturities and repayments will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2015; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the expectation that economic conditions in Arizona will improve; projected electricity sales growth at the Caribbean Regulated Electric Utilities; the impact of advances in technology and new energy efficiency standards on the Corporation's results of operations; the impact of new or revised environmental laws and regulations on the Corporation's results of operations; the expectation that any liability from current legal proceedings will not have a material adverse effect on the Corporation's consolidated financial position and results of operations; the belief that the Corporation has a strong, well-positioned case supporting the unconstitutionality of the expropriation of the Corporation's investment in Belize; the expectation that ongoing labour negotiations will be settled in 2015; and the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporations consolidated financial statements.

The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: a favorable outlook for the potential sale of assets or shares in the hotel and commercial real estate markets; the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; FortisAlberta's continued recovery of its cost of service and ability to earn its allowed ROE under performance-based rate-setting ("PBR"), which commenced for a five-year term effective January 1, 2013; no significant variability in interest rates; 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 events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; no material capital project and financing cost overrun related to the construction of the non-regulated Waneta Expansion hydroelectric generating facility; sufficient liquidity and capital resources; the expectation that the Corporation will receive appropriate compensation from the Government of Belize ("GOB") for fair value of the Corporation's investment in Belize Electricity Limited ("Belize Electricity") that was expropriated by the GOB; the expectation that Belize Electric Company Limited will not be expropriated by the GOB; the continuation of local development projects in the Turks and Caicos Islands in 2015;
the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; 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, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans and environmental laws that may materially negatively affect the operations and cash flows of the Corporation and its subsidiaries; no material change in public policies and directions by governments that could materially negatively affect the Corporation and its subsidiaries; new or revised environmental laws and regulations will not severely affect the results of operations; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the ability to report under US GAAP beyond 2018 or the adoption of International Financial Reporting Standards after 2018 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; 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. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2015 include, but are not limited to: uncertainty of the impact a continuation of a low interest rate environment may have on the allowed ROE at the Corporation's regulated utilities; uncertainty regarding the treatment of certain capital expenditures at FortisAlberta under the newly implemented PBR mechanism; risk associated with the amount of compensation to be paid to Fortis for its investment in Belize Electricity that was expropriated by the GOB; and the timeliness of the receipt of the compensation and the ability of the GOB to pay the compensation owing to Fortis.

All forward-looking information in the MD&A 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

Fortis is a leader in the North American electric and gas utility business, with total assets of more than $26 billion and fiscal 2014 revenue of $5.4 billion. Its regulated utilities account for approximately 93% of total assets and serve more than 3 million customers across Canada and in the United States and the Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada, Belize and Upstate New York. The Corporation's non-utility investment is comprised of hotels and commercial real estate in Canada. In 2014 the Corporation's electricity distribution systems met a combined peak demand of 9,740 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,557 terajoules.

The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation and, in certain circumstances, performance-based rate-setting ("PBR") mechanisms. Generally, under COS regulation the respective regulatory authority sets customer electricity and/or gas rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") depends on the utility achieving the forecasts established in the rate-setting processes. When PBR mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudently incurred costs and earn its allowed ROE or ROA.

Earnings of regulated utilities are generally impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA and common equity component of capital structure; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) timing differences within an annual financial reporting period between when actual expenses are incurred and when they are recovered from customers in rates. When future test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of the actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. In addition, the Corporation's regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms.

Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated generation and non-utility assets, which are treated as two separate segments. The Corporation's investments in non-regulated assets provide financial, tax and regulatory flexibility and enhance shareholder return.

The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.

The following summary describes the operations included in each of the Corporation's reportable segments.

REGULATED UTILITIES

The Corporation's interests in regulated electric and gas utilities are as follows.

Regulated Electric & Gas Utilities - United States

  1. UNS Energy: Primarily comprised of Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"), (collectively, the "UNS Utilities"), acquired by Fortis in August 2014.

    TEP, UNS Energy's largest operating subsidiary, is a vertically integrated regulated electric utility. TEP generates, transmits and distributes electricity to approximately 415,000 retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells wholesale electricity to other entities in the western United States.

    UNS Electric is a vertically integrated regulated electric utility, which generates, transmits and distributes electricity to approximately 93,000 retail electric customers in Arizona's Mohave and Santa Cruz counties.

    TEP and UNS Electric currently own or lease generation resources with an aggregate capacity of 2,746 MW, including 53 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at January 1, 2015, approximately 48% of the generating capacity is fuelled by coal.

    UNS Gas is a regulated gas distribution company. The Company serves approximately 150,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.
  2. Central Hudson: Central Hudson Gas & Electric Corporation ("Central Hudson") is a regulated transmission and distribution ("T&D") utility, serving approximately 300,000 electricity customers and 77,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. The Company owns minimal gas-fired and hydroelectric generating capacity totalling 64 MW. Central Hudson was acquired by Fortis in June 2013.

Regulated Gas Utilities - Canadian

FortisBC Energy Companies: Primarily includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"), (collectively, the "FortisBC Energy companies"). On December 31, 2014, FEI, FEVI and FEWI were amalgamated and FEI is the resulting Company.

FEI is the largest distributor of natural gas in British Columbia, serving approximately 967,000 customers in more than 125 communities. Major areas served by the Company are the Lower Mainland, Vancouver Island, Sunshine Coast, Whistler and Interior of British Columbia.

FEI provides T&D services to customers, and obtains natural gas supplies on behalf of most residential, commercial and industrial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through FEI's Southern Crossing pipeline, from Alberta.

Regulated Electric Utilities - Canadian

  1. FortisAlberta: FortisAlberta Inc. ("FortisAlberta") owns and operates the electricity distribution system in a substantial portion of southern and central Alberta, serving approximately 530,000 customers. The Company does not own or operate generation or transmission assets and is not involved in the direct sale of electricity.
  1. FortisBC Electric: Includes FortisBC Inc., an integrated electric utility operating in the southern interior of British Columbia, serving approximately 166,000 customers directly and indirectly. FortisBC Inc. owns four hydroelectric generating facilities with a combined capacity of 225 MW. Also included in the FortisBC Electric segment are the operating, maintenance and management services relating to the 493-MW Waneta hydroelectric generating facility owned by Teck Metals Ltd. and BC Hydro, the 149-MW Brilliant hydroelectric plant and the 120-MW Brilliant hydroelectric expansion plant, both owned by Columbia Power Corporation and Columbia Basin Trust ("CPC/CBT"), and the 185-MW Arrow Lakes hydroelectric plant owned by CPC/CBT. In March 2013 FortisBC Inc. acquired the City of Kelowna's electric utility assets.
  1. Eastern Canadian: Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited ("Maritime Electric") and FortisOntario Inc. ("FortisOntario"). Newfoundland Power is an integrated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador, serving approximately 259,000 customers. Newfoundland Power has an installed generating capacity of 139 MW, of which 97 MW is hydroelectric generation. Maritime Electric is an integrated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI"), serving approximately 78,000 customers. Maritime Electric also maintains on-Island generating facilities with a combined capacity of 150 MW. FortisOntario provides integrated electric utility service to approximately 65,000 customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. FortisOntario's operations are primarily comprised of Canadian Niagara Power Inc. ("Canadian Niagara Power"), Cornwall Street Railway, Light and Power Company, Limited ("Cornwall Electric") and Algoma Power Inc. ("Algoma Power").

Regulated Electric Utilities - Caribbean

The Regulated Electric Utilities - Caribbean segment includes Caribbean Utilities Company, Ltd. ("Caribbean Utilities") and Fortis Turks and Caicos. Caribbean Utilities is an integrated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands, serving approximately 28,000 customers. The Company has an installed diesel-powered generating capacity of 132 MW. Fortis holds an approximate 60% controlling ownership interest in Caribbean Utilities (December 31, 2013 - 60%). Caribbean Utilities is a public company traded on the Toronto Stock Exchange ("TSX") (TSX:CUP.U). Fortis Turks and Caicos is comprised of two integrated electric utilities serving approximately 13,000 customers on certain islands in Turks and Caicos. The utilities have a combined diesel-powered generating capacity of 76 MW.

NON-REGULATED - FORTIS GENERATION

Fortis Generation includes the financial results of non-regulated generation assets in Belize, British Columbia, Upstate New York and Ontario.

Generating assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW. All of the output of these facilities is sold to Belize Electricity Limited ("Belize Electricity") under 50-year power purchase agreements ("PPAs") expiring in 2055 and 2060. The hydroelectric generation operations in Belize are conducted through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL") under a franchise agreement with the Government of Belize ("GOB").

In British Columbia, generating assets include the 16-MW run-of-river Walden hydroelectric generating facility ("Walden") and the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion"). All of the output of Walden is sold to BC Hydro under a long-term contract that cannot be terminated prior to 2024. Construction of the Waneta Expansion, which is adjacent to the Waneta Dam and powerhouse facilities on the Pend d'Oreille River, south of Trail, British Columbia, commenced late in 2010 and the facility is expected to come into service in spring 2015. The output of the Waneta Expansion will be sold to BC Hydro and FortisBC Electric under 40-year contracts. The Corporation's 51% controlling ownership interest in the Waneta Expansion is conducted through the Waneta Expansion Limited Partnership ("Waneta Partnership"), with CPC/CBT holding the remaining 49% interest.

Generating assets in Upstate New York are comprised of four hydroelectric generating facilities with a combined capacity of approximately 23 MW, operating under licences from the U.S. Federal Energy Regulatory Commission ("FERC"). Hydroelectric generation operations in Upstate New York are conducted through the Corporation's indirectly wholly owned subsidiary FortisUS Energy Corporation ("FortisUS Energy").

In Ontario, generating assets include six small hydroelectric generating facilities with a combined capacity of 8 MW and a 5-MW gas-powered cogeneration plant in Cornwall.

NON-REGULATED - NON-UTILITY

The Non-Utility segment includes Fortis Properties Corporation ("Fortis Properties") and, from June 2013 through March 2014, Griffith Energy Services, Inc. ("Griffith"). Fortis Properties owns and operates 23 hotels, comprised of more than 4,400 rooms, in eight Canadian provinces, and owns and operates approximately 2.8 million square feet of commercial office and retail space, primarily in Atlantic Canada. In September 2014 the Corporation announced that it would engage in a review of strategic options for its hotel and commercial real estate business. For further information on the strategic review, refer to the "Significant Items - Review of Strategic Options for Fortis Properties" section of this MD&A.

Griffith was acquired by Fortis as part of the acquisition of Central Hudson in June 2013 and was sold in March 2014. For further information on the sale of Griffith, refer to the "Significant Items - Sale of Griffith" section of this MD&A.

CORPORATE AND OTHER

The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments.

The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group, Inc. and UNS Energy Corporation. Net Corporate expenses include finance charges; dividends on preference shares; other corporate expenses, including corporate operating costs, net of recoveries from subsidiaries; acquisition-related expenses; interest and miscellaneous revenue; and related income taxes.

Also included in the Corporate and Other segment are the financial results of FortisBC Alternative Energy Services Inc. ("FAES"). FAES is a wholly owned subsidiary of FHI that provides alternative energy solutions, including thermal-energy and geo-exchange systems.

CORPORATE STRATEGY

Fortis is a leader in the North American utility industry. In all its operations, Fortis will manage resources prudently and deliver quality service to maximize value to customers and shareholders. The Fortis strategy is directed at long-term profitable growth. Earnings per common share and total shareholder return are the primary measures of performance.

Over the 10-year period ended December 31, 2014, earnings per common share of Fortis grew at a compound annual growth rate of 2.8%. Over the same period, Fortis delivered an average annualized total return to shareholders of approximately 12%, exceeding the S&P/TSX Capped Utilities and S&P/TSX Composite Indices, which delivered average annualized performance of approximately 8% over the same period.

The Corporation's first priority remains the continued profitable expansion of existing operations. Fortis has also demonstrated its ability to acquire additional regulated utilities in Canada and the United States. Management is focused on the full integration of UNS Energy within Fortis and executing the Corporation's substantial capital program.

The acquisitions of Central Hudson in June 2013 and UNS Energy in August 2014 represent the Corporation's initial investments into the regulated U.S. utility market. These U.S. regulated utility assets further mitigate business risk for Fortis by enhancing the geographic diversification of the Corporation's regulated assets, resulting in no more than one-third of total assets being located in any one regulatory jurisdiction. For further information on the acquisition of UNS Energy, refer to the "Significant Items - Acquisition of UNS Energy" section of this MD&A.

The principal business of Fortis is, and will remain, the ownership and operation of regulated electric and gas utilities. The key goals of the Corporation's regulated utilities are to operate sound electricity and gas distribution systems; deliver safe, reliable, cost-efficient energy to customers; and conduct business in an environmentally responsible manner.

KEY TRENDS, RISKS AND OPPORTUNITIES

General Trends for the Energy Sector: The North American energy market has changed rapidly over the past several years. The most notable change has been technological advances in drilling and well completion techniques that have rapidly transformed the outlook for North American natural gas and oil production. Notwithstanding the changes occurring in the energy industry, safety, reliability and serving customers at the lowest reasonable cost remain at the forefront of the utility industry's key issues.

According to ExxonMobil's 2015 Outlook for Energy: A View to 2040, global energy demand is expected to increase by approximately 35% from 2010 to 2040. The world will likely continue to become more energy efficient as demand increases. However, without the efficiency gains, the global energy demand could grow by as much as 140% over the same period. The world's energy future will see a shift to lower-carbon fuels, stable greenhouse gas ("GHG") emissions, and technologies with new energy options, such as unconventional oil and natural gas in North America. North America is likely to transition into a net exporter of liquid petroleum products by 2020 due to increased supplies of tight oil, natural gas liquids and bitumen from oil sands. The increased demand for natural gas is expected to be met by 2040 as the liquefied natural gas trade is expected to triple and unconventional gas production nearly quadruple, due to new supplies and significant trade expansion.

As noted in the National Energy Board's energy market assessment report, Canada's Energy Future 2013: Energy Supply and Demand Projections to 2035, the country has considerable energy resources and its total energy production is expected to grow substantially by 2035, with oil production expected to lead the growth at 75%, and natural gas production at 25%, led by higher levels of tight oil and shale gas development. Total energy consumed by Canadians is expected to continue to grow, but at a slower rate than in the past. By 2035, the country's demand for oil and natural gas is expected to increase by 28%. Canada's total electricity generation, which is more than 80% from non-emitting sources, is expected to increase 27% by 2035. Natural gas-powered generation capacity is expected to increase considerably, but at the expense of coal-powered capacity as a result of federal and provincial regulations.

The Conference Board of Canada estimates that $350 billion over the 20-year period through 2030, must be invested in Canada's electricity infrastructure in order to meet the demands of a growing population and new technologies. Over the past four decades, investments have averaged between $9 billion and $11 billion, annually.

The U.S. Energy Information Administration's Annual Energy Outlook 2014 with Projections to 2040 reports that electricity demand growth in the United States remains relatively low, as rising demand for electric services is offset by energy efficiencies gained from new appliance standards and investments in energy-efficient equipment. Total electricity demand is expected to grow by 29% through to 2040. Growing domestic production of natural gas and oil is expected to continue to reshape the U.S. energy economy, largely the result of rising production from tight geological formations. Industrial production is expected to expand over the next 10 to 15 years as the competitive advantage of low natural gas prices provides a boost to the industrial sector. The higher level of industrial production is expected to lead to a 22% increase in natural gas consumption in the U.S. industrial sector through 2025. The ever-evolving natural gas markets have created a demand for natural gas for electricity generation and transportation and have increased export opportunities. As natural gas prices rise and the capital costs of renewable technologies (wind and solar) decrease over time, renewable generation becomes more competitive, and is expected to account for 16% of total electricity generation by 2040. Natural gas-fired generation is expected to overtake coal-fired generation in 2019, and by 2040 the natural gas share of total generation is expected to reach 43%. Improved efficiency of energy use in the residential and transportation sectors and a move from more carbon-intensive fuels, such as coal, for electricity generation will help stabilize the country's GHG emissions.

The Edison Electric Institute reported US$90 billion in annual capital expenditures for the U.S. electric power industry for 2012 and 2013. Electric utilities in the United States anticipate investing, on average, close to US$100 billion annually for 2014 through 2016.

Regulation: The Corporation's key business risk is regulation. Each of the Corporation's nine utilities is subject to regulation by the regulatory body in its respective operating jurisdiction. Relationships with the regulatory authorities are managed at the local utility level.

Commitment by the Corporation's utilities to provide safe and reliable service, operational excellence and to promote positive customer and regulatory relations is important for supportive regulatory relationships and obtaining full cost recovery and competitive returns for the Corporation's shareholders.

Significant regulatory uncertainty remains at FortisAlberta associated with the capital tracker mechanism under the PBR formula, which became effective January 1, 2013. In May 2014 FortisAlberta filed a combined 2013, 2014 and 2015 Capital Tracker Application, which requested capital tracker revenue of approximately $23 million for 2013, $48 million for 2014 and $69 million for 2015. For 2013 and 2014, FortisAlberta recognized capital tracker revenue of approximately $15 million and $30 million, respectively, based on the interim regulatory decision granting 60% of the applied for capital tracker amounts. In December 2014 the regulator approved, on an interim basis, customer distribution rates for 2015 based on 90% of the applied for capital tracker amounts. The final decision on FortisAlberta's combined 2013, 2014 and 2015 Capital Tracker Application is expected in the first quarter of 2015.

For a further discussion of regulatory risk and the nature of regulation and material regulatory decisions and applications pertaining to the Corporation's regulated utilities, refer to the "Business Risk Management - Regulatory Risk" and "Regulatory Highlights" sections of this MD&A.

Capital Expenditure Program and Rate Base Growth: The Corporation's regulated midyear rate base for 2014 was approximately $14 billion. Over the five years 2015 through 2019, the Corporation's consolidated capital expenditure program is expected to approach $9 billion. Over the same period, this level of capital investment is expected to result in an estimated five-year compound annual growth rate in midyear rate base of approximately 6.5%. Fortis expects that investment in its utilities associated with their capital expenditure programs will support continuing growth in earnings and dividends.

For further information on the Corporation's consolidated capital expenditure program and rate base of its regulated utilities, refer to the "Liquidity and Capital Resources - Capital Expenditure Program" section of this MD&A.

Natural Gas Opportunities: The FortisBC Energy companies are pursuing opportunities in British Columbia for gas infrastructure. The combination of an abundant supply of natural gas, low costs for natural gas and supportive government policy are generating new interest for large industrial customers and niche liquefied natural gas ("LNG") producers to utilize the FortisBC Energy companies' gas system.

In November 2013 the Government of British Columbia issued an Order in Council announcing the exemption of FEI's Tilbury LNG facility expansion ("Tilbury Expansion") from normal course regulatory review and imposing an upper limit of $400 million of capital costs associated with the expansion. FEI has begun the expansion, which will increase LNG production and storage capabilities, and it is expected to be in service by the end of 2016. Since this announcement, there has been considerable interest for LNG supply from the Pacific Northwest, Hawaii, Alaska and international markets. In December 2014 the Government of British Columbia issued a second Order in Council amending directions to the regulator regarding the Tilbury Expansion. The revisions set out a number of requirements for the regulator, including the consideration of a second phase of the Tilbury Expansion that would include additional liquefaction and could increase the overall project cost for both phases of the Tilbury Expansion to $850 million. For further information, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.

Traditionally, the majority of natural gas production in northern British Columbia has served the provincial and Pacific Northwest markets via the Westcoast (Spectra) system. However, to realize the full potential of British Columbia shale gas plays, additional capacity to connect to markets will have to be developed. The FortisBC Energy companies are exploring pipeline investment opportunities that include expansion of their existing distribution system to supply natural gas to a prospective LNG export facility, as well as to expand capacity on their Southern Crossing transmission pipeline. The FortisBC Energy companies are pursuing a potential $600 million pipeline expansion for the proposed Woodfibre LNG site in British Columbia. The Woodfibre site is a former paper mill site located near Squamish, British Columbia. The Companies have an opportunity to expand their gas pipeline and increase compression to deliver natural gas to this site.

Access to Capital and Liquidity: The Corporation's regulated utilities require ongoing access to long-term capital to fund investments in infrastructure necessary to provide service to customers. Long-term capital required to carry out the utility capital expenditure programs is mostly obtained at the regulated utility level. The regulated utilities usually issue debt at terms ranging between 10 and 50 years. As at December 31, 2014, almost 90% of the Corporation's consolidated long-term debt, excluding borrowings under long-term committed credit facilities, had maturities beyond five years. Management expects consolidated long-term debt maturities and repayments to average approximately $240 million annually over the next five years, excluding long-term credit facility borrowings.

To help ensure uninterrupted access to capital and sufficient liquidity to fund capital programs and working capital requirements, the Corporation and its subsidiaries have approximately $3.9 billion in credit facilities, of which approximately $2.2 billion was unused as at December 31, 2014. Based on current credit ratings and conservative capital structures, the Corporation and its regulated utilities expect to continue to have reasonable access to long-term capital in 2015.

Dividend Increases: Dividends paid per common share increased to $1.28 in 2014. Fortis increased its quarterly common share dividend to 34 cents, commencing with the first quarter dividend to be paid in 2015. The 6.25% increase in the quarterly common share dividend translates into an annualized dividend of $1.36 for 2015 and extends the Corporation's record of annual common share dividend increases to 42 consecutive years, the record for a public corporation in Canada.

Expropriated Assets: The GOB expropriated the Corporation's common share ownership in Belize Electricity in June 2011. The Corporation is challenging the constitutionality of the expropriation in the Belize Courts. There has been no settlement on the fair value compensation owing to Fortis as a result of the expropriation. As at December 31, 2014, the book value of the Corporation's expropriated investment in Belize Electricity is $116 million, including foreign exchange impacts. The Corporation is awaiting a decision on its appeal to the Caribbean Court of Justice ("CCJ"). For further information, refer to the "Business Risk Management - Expropriation of Shares in Belize Electricity" section of this MD&A.

SIGNIFICANT ITEMS

Acquisition of UNS Energy: On August 15, 2014, Fortis acquired all of the outstanding common shares of UNS Energy for US$60.25 per common share in cash, for an aggregate purchase price of approximately US$4.5 billion, including the assumption of US$2.0 billion of debt on closing. UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona, engaged through its primary subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 658,000 electricity and gas customers. UNS Energy has three regulated utility subsidiaries: TEP, UNS Electric and UNS Gas. UNS Energy's utility operations are vertically integrated with generation, transmission and distribution being regulated by the Arizona Corporation Commission ("ACC") and FERC. For further information on UNS Energy, refer to the "Segmented Results of Operations - Regulated Electric & Gas Utilities - United States" section of this MD&A.

Financing of the net cash purchase price of approximately $2.7 billion (US$2.5 billion) is substantially complete. Fortis completed the sale of $1.8 billion 4% convertible unsecured subordinated debentures represented by installment receipts ("Convertible Debentures"), as further discussed below. Proceeds from the first installment of approximately $599 million were received in January 2014. A significant portion of these cash proceeds were used to finance a portion of the UNS Energy acquisition. Proceeds from the final installment of approximately $1.2 billion were received on October 28, 2014 and were used to repay borrowings under acquisition credit facilities initially used to finance a portion of the UNS Energy acquisition. Following the receipt of the final installment, on October 28, 2014, approximately 58.2 million common shares of Fortis were issued on conversion of the Convertible Debentures. In September 2014 Fortis issued 24 million 4.1% Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series M for gross proceeds of $600 million. The net proceeds were also used to repay a portion of borrowings under the acquisition credit facilities. The remainder of the purchase price was financed through credit facility borrowings under a medium-term bridge facility and the Corporation's revolving credit facility.

Convertible Debentures: To finance a portion of the acquisition of UNS Energy, in January 2014, Fortis completed the sale of $1.8 billion aggregate principal amount of 4% Convertible Debentures. The Convertible Debentures were sold on an installment basis at a price of $1,000 per Convertible Debenture, of which $333 was paid on closing in January 2014 and the remaining $667 was paid on October 27, 2014 (the "Final Installment Date"). Prior to the Final Installment Date, the Convertible Debentures were represented by Installment Receipts, which were traded on the TSX under the symbol "FTS.IR". Since the Final Installment Date occurred prior to the first anniversary of the closing of the offering, holders of Convertible Debentures received, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing interest that would have accrued from the day following the Final Installment Date to and including January 9, 2015. Approximately $72 million ($51 million after tax) in interest expense associated with the Convertible Debentures, including the make-whole payment, was recognized in 2014.

At the option of the holders, each Convertible Debenture was convertible into common shares of Fortis at any time after the Final Installment Date but prior to maturity or redemption by the Corporation at a conversion price of $30.72 per common share, being a conversion rate of 32.5521 common shares per $1,000 principal amount of Convertible Debentures. On October 28, 2014, approximately 58.2 million common shares of Fortis were issued, representing conversion into common shares of more than 99% of the Convertible Debentures. As at December 31, 2014, a total of approximately 58.5 million common shares of Fortis were issued on the conversion of Convertible Debentures for proceeds of $1.747 billion, net of after-tax expenses. The net proceeds were used to finance a portion of the acquisition of UNS Energy.

Review of Strategic Options for Fortis Properties: In September 2014 the Corporation announced that it would engage in a review of strategic options for its hotel and commercial real estate business, operating as Fortis Properties. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering. A decision on this review is expected to be made in the second quarter of 2015.

Sale of Griffith: In March 2014 Griffith was sold for proceeds of approximately $105 million (US$95 million). The results of operations have been presented as discontinued operations on the consolidated statements of earnings for the years ended December 31, 2014 and 2013. Earnings for 2014 included $5 million associated with Griffith from normal operations to the date of sale.

SUMMARY FINANCIAL HIGHLIGHTS

For the Years Ended December 31 2014 2013 Variance
Net Earnings Attributable to Common Equity Shareholders ($ millions) 317 353 (36 )
Basic Earnings per Common Share ($) 1.41 1.74 (0.33 )
Diluted Earnings per Common Share ($) 1.40 1.73 (0.33 )
Weighted Average Number of Common Shares Outstanding (millions) 225.6 202.5 23.1
Cash Flow from Operating Activities ($ millions) 982 899 83
Dividends Paid per Common Share ($) 1.28 1.24 0.04
Dividend Payout Ratio (%) 90.8 71.3 19.5
Return on Average Book Common Shareholders' Equity (%) (1) 5.4 8.1 (2.7 )
Total Assets ($ billions) 26.6 17.9 8.7
Gross Capital Expenditures ($ millions) 1,725 1,175 550
Public Common Share Offering ($ millions) - 601 (601 )
Public Preference Share Offerings ($ millions) 600 250 350
Convertible Debenture Offering ($ millions) 1,800 - 1,800
Long-Term Debt Offerings ($ millions) 1,200 657 543
(1) Return on average book common shareholders' equity is a non-US GAAP measure and is defined as net earnings attributable to common equity shareholders divided by the average of opening and closing consolidated shareholders' equity, excluding preference shares and non-controlling interests. Return on average book common shareholders' equity is referred to by users of the Corporation's consolidated financial statements in evaluating the results of operations.

Net Earnings Attributable to Common Equity Shareholders: Fortis achieved net earnings attributable to common equity shareholders of $317 million in 2014 compared to $353 million in 2013. Results for both years were impacted by non-recurring items, largely associated with the acquisition of UNS Energy in 2014 and Central Hudson in 2013. Earnings for 2014 were reduced by $39 million due to acquisition-related expenses and customer benefits offered to obtain regulatory approval of the acquisition of UNS Energy, compared to $34 million associated with the acquisition of Central Hudson in 2013. Interest expense of $51 million after tax, including the make-whole payment, associated with Convertible Debentures issued to finance a portion of the acquisition of UNS Energy was recognized in 2014. In addition, earnings for 2013 were favourably impacted by an income tax recovery of $23 million due to the enactment of higher deductions associated with Part VI.1 tax on the Corporation's preference share dividends, and an extraordinary gain of $20 million related to the settlement of expropriation matters associated with the Exploits Partnership. Excluding the above-noted impacts, net earnings attributable to common equity shareholders for 2014 were $407 million, an increase of $63 million from $344 million for 2013.

The Corporation's regulated utilities contributed earnings of $460 million compared to $392 million for 2013. The increase was driven by $60 million of earnings contribution at UNS Energy from the date of acquisition and the first full year of earnings contribution from Central Hudson, which was acquired in June 2013. FortisAlberta's earnings were $9 million higher year over year, driven by rate base growth and an increase in the number of customers. Earnings at Caribbean Regulated Electric Utilities were $4 million higher than 2013, driven by electricity sales growth. The increases were partially offset by lower earnings at Eastern Canadian Electric Utilities, due to income tax recoveries of approximately $17 million in 2013 associated with Part VI.1 tax, and at FortisBC Electric, primarily due to the impact of lower-than-expected finance charges in 2013. Earnings at the FortisBC Energy companies were comparable with 2013.

Non-Regulated Fortis Generation contributed $20 million to earnings compared to $39 million for 2013. The decrease was primarily due to the recognition of an approximate $20 million after-tax extraordinary gain on the settlement of expropriation matters associated with the Exploits Partnership in 2013.

Non-Utility operations contributed earnings of $28 million, an increase of $10 million from 2013. Earnings for 2014 included $5 million associated with Griffith compared to a loss of $5 million for 2013. Earnings at Fortis Properties of $23 million were comparable with 2013.

Corporate and Other expenses were $33 million higher year over year, excluding the impacts of interest expense on the Convertible Debentures, acquisition-related expenses and income tax recoveries of approximately $6 million associated with Part VI.1 tax in 2013. The increase was primarily due to higher finance charges, largely due to the acquisitions of UNS Energy and Central Hudson, and higher operating expenses. The increase in operating expenses was mainly due to employee-related expenses, including approximately $11 million in one-time after-tax retirement expenses; share-based compensation expenses, as a result of share price appreciation; higher legal and consulting fees; and general inflationary increases. The increase in Corporate and Other expenses was partially offset by an $8 million foreign exchange gain compared to $6 million in 2013, a higher income tax recovery and interest income.

Basic Earnings per Common Share: Basic earnings per common share were $1.41 in 2014 compared to $1.74 in 2013. Excluding the above-noted non-recurring items in 2014 and 2013, basic earnings per common share were $1.81 for 2014, an increase of $0.11 from $1.70 for 2013. The increase was driven by accretion associated with the acquisition of UNS Energy.

A graph is available at the following address: http://media3.marketwire.com/docs/BasicEarningsPerCommonShares.pdf

Cash Flow from Operating Activities: Cash flow from operating activities was $982 million for 2014, an increase of $83 million from 2013. The increase was driven by higher cash earnings, partially offset by unfavourable changes in working capital and long-term regulatory deferrals.

A graph is available at the following address: http://media3.marketwire.com/docs/CashFlowOperatingActivities.pdf

Dividends: Dividends paid per common share increased to $1.28 in 2014, 3.2% higher than $1.24 in 2013. Fortis increased its quarterly common share dividend to 34 cents from 32 cents, commencing with the first quarter dividend payable on March 1, 2015. The Corporation's dividend payout ratio was 90.8% in 2014 compared to 71.3% in 2013. Excluding the above-noted non-recurring items in 2014 and 2013, the dividend payout ratio was 70.7% in 2014, comparable with 72.9% in 2013.

A graph is available at the following address: http://media3.marketwire.com/docs/DividendsPaidCommonShare.pdf

Return on Average Book Common Shareholders Equity: The return on average book common shareholders' equity for 2014 was 5.4% compared to 8.1% for 2013. Excluding the above-noted non-recurring items in 2014 and 2013, the return on average book common shareholders' equity for 2014 was 7.0%, comparable with 7.9% for 2013.

Total Assets: Total assets increased 48.6% to approximately $26.6 billion at the end of 2014 compared to approximately $17.9 billion at the end of 2013. The increase reflects the Corporation's acquisition of UNS Energy in August 2014 and continued investment in energy infrastructure, driven by capital spending at the regulated utilities in western Canada and the Waneta Expansion.

A graph is available at the following address: http://media3.marketwire.com/docs/Total_Assets.pdf

Gross Capital Expenditures: Consolidated capital expenditures, before customer contributions, were $1,725 million in 2014 compared to $1,175 million in 2013. The increase was driven by capital investment of $444 million (US$388 million) at UNS Energy from the date of acquisition, including the purchase of Unit 3 of the Gila River generating station, which is a gas-fired combined-cycle unit with a capacity of 550 MW, in December 2014 for $252 million (US$219 million). The regulated utilities in western Canada invested $772 million in 2014, or approximately 45% of consolidated capital expenditures. Capital investment was driven by the construction of the FortisBC Energy companies' Tilbury Expansion in British Columbia, which commenced in October 2014, customer growth and the ongoing need to enhance the reliability and efficiency of energy systems. Construction of the $900 million, 335-MW Waneta Expansion continues on time and on budget, with completion of the facility expected in spring 2015. Approximately $100 million was spent on the Waneta Expansion in 2014, for a total of approximately $679 million since construction began in late 2010. For a further discussion of the Corporation's consolidated capital expenditure program, refer to the "Liquidity and Capital Resources - Capital Expenditure Program" section of this MD&A.

Long-Term Capital: Fortis completed the sale of $1.8 billion Convertible Debentures in 2014 to finance a portion of the acquisition of UNS Energy. In October 2014 approximately 58.2 million common shares of Fortis were issued on conversion of the debentures. In September 2014 Fortis issued 24 million 4.1% Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series M for gross proceeds of $600 million. The net proceeds were also used to finance a portion of the acquisition of UNS Energy. The Corporation and its regulated utilities raised approximately $1.2 billion in long-term debt in 2014. For further information, refer to the "Liquidity and Capital Resources - Summary of Consolidated Cash Flows" section of this MD&A.

CONSOLIDATED RESULTS OF OPERATIONS

Years Ended December 31
($ millions) 2014 2013 Variance
Revenue 5,401 4,047 1,354
Energy Supply Costs 2,197 1,617 580
Operating Expenses 1,493 1,037 456
Depreciation and Amortization 688 541 147
Other Income (Expenses), Net (25 ) (31 ) 6
Finance Charges 547 389 158
Income Tax Expense 66 32 34
Earnings From Continuing Operations 385 400 (15 )
Earnings From Discontinued Operations, Net of Tax 5 - 5
Earnings Before Extraordinary Item 390 400 (10 )
Extraordinary Gain, Net of Tax - 20 (20 )
Net Earnings 390 420 (30 )
Net Earnings Attributable to:
Non-Controlling Interests 11 10 1
Preference Equity Shareholders 62 57 5
Common Equity Shareholders 317 353 (36 )
Net Earnings 390 420 (30 )

Revenue

The increase in revenue was driven by the acquisition of UNS Energy in August 2014 and Central Hudson in June 2013. A higher commodity cost of natural gas charged to customers at the FortisBC Energy companies, an increase in the base component of rates at most of the regulated utilities and higher electricity sales also contributed to the increase in revenue.

Energy Supply Costs

The increase in energy supply costs was primarily due to the acquisition of UNS Energy and Central Hudson. A higher commodity cost of natural gas at the FortisBC Energy companies and higher electricity sales also contributed to the increase in fuel, power and natural gas purchases.

Operating Expenses

The increase in operating expenses was primarily due to the acquisition of UNS Energy and Central Hudson, and general inflationary and employee-related cost increases, including approximately $13 million ($11 million after tax) in retirement expenses recognized in 2014.

Depreciation and Amortization

The increase in depreciation and amortization was due to the acquisition of UNS Energy and Central Hudson, and continued investment in energy infrastructure at the Corporation's regulated utilities.

Other Income (Expenses), Net

Other income, net of expenses for 2014 was comparable with last year. Total acquisition-related expenses associated with UNS Energy in 2014 was comparable with acquisition-related expenses associated with Central Hudson in 2013.

Finance Charges

The increase in finance charges was primarily due to approximately $72 million ($51 million after tax) in interest expense, including the make-whole payment, associated with the Convertible Debentures issued to finance a portion of the acquisition of UNS Energy. The increase was also due to the UNS Energy and Central Hudson acquisitions, including interest expense on debt issued to complete the financing of the acquisitions.

Income Tax Expense

The increase in income tax expense was primarily due to the impact of an income tax recovery of $23 million in 2013, due to the enactment of higher deductions associated with Part VI.1 tax, and the release of income tax provisions of $7 million in 2013.

Earnings from Discontinued Operations, Net of Tax

Earnings for 2014 include $5 million associated with Griffith from normal operations to the date of sale in March 2014.

Extraordinary Gain, Net of Tax

An approximate $20 million after-tax extraordinary gain was recognized in 2013 on the settlement of expropriation matters associated with the Exploits Partnership.

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
Years Ended December 31
($ millions) 2014 2013 Variance
Regulated Electric & Gas Utilities - United States
UNS Energy 60 - 60
Central Hudson 37 23 14
97 23 74
Regulated Gas Utilities - Canadian
FortisBC Energy Companies 127 127 -
Regulated Electric Utilities - Canadian
FortisAlberta 103 94 9
FortisBC Electric 46 50 (4 )
Eastern Canadian 60 75 (15 )
209 219 (10 )
Regulated Electric Utilities - Caribbean 27 23 4
Non-Regulated - Fortis Generation 20 39 (19 )
Non-Regulated - Non-Utility 28 18 10
Corporate and Other (191 ) (96 ) (95 )
Net Earnings Attributable to Common Equity Shareholders 317 353 (36 )

The following is a discussion of the financial results of the Corporation's reporting segments. A discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Corporation's regulated utilities is provided in the "Regulatory Highlights" section of this MD&A.

REGULATED UTILITIES

The Corporation's primary business is the ownership and operation of regulated utilities. In 2014 regulated earnings represented approximately 91% (2013 - 87%) of the Corporation's earnings from its operating segments (excluding Corporate and Other segment expenses). Total regulated assets represented 93% of the Corporation's total assets as at December 31, 2014 (December 31, 2013 - 90%).

REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES

Regulated Electric & Gas Utilities - United States earnings for 2014 were $97 million (2013 - $23 million), which represented approximately 21% (2013 - 6%) of the Corporation's total regulated earnings. Total segment assets were approximately $10.1 billion as at December 31, 2014 (December 31, 2013 - $2.3 billion), which represented approximately 41% of the Corporation's total regulated assets as at December 31, 2014 (December 31, 2013 -14%).

A graph is available at the following address: http://media3.marketwire.com/docs/RegulatedElectricGasUtilities.pdf

UNS ENERGY

Financial Highlights (1)
Year Ended December 31 2014
Average US:CDN Exchange Rate (2) 1.12
Electricity Sales (gigawatt hours ("GWh")) 5,646
Gas Volumes (petajoules ("PJ")) 5
Revenue ($ millions) 684
Earnings ($ millions) 60
(1) Financial results of UNS Energy are from August 15, 2014, the date of acquisition. For additional information on the acquisition of UNS Energy, refer to the "Significant Items - Acquisition of UNS Energy" section of this MD&A.
(2) The reporting currency of UNS Energy is the US dollar. The average US:CDN exchange rate is from the date of acquisition.

Electricity Sales & Gas Volumes

Electricity sales were 5,646 gigawatt hours ("GWh") from the date of acquisition. On an annual basis, electricity sales were 14,560 GWh for 2014, comparable with 14,567 GWh for 2013. The slight decrease was due to milder summer temperatures, which reduced the use of air conditioning and other cooling equipment.

Gas volumes were 5 petajoules ("PJ") from the date of acquisition. On an annual basis, gas volumes were 13 PJ for 2014 compared to 14 PJ for 2013. The decrease was primarily due to warmer weather in 2014 during the heating season.

Seasonality impacts the revenue of UNS Energy. Earnings for the electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment and earnings for the gas utility are generally highest in the first and fourth quarters due to space-heating requirements.

Revenue

Revenue was US$610 million from the date of acquisition. On an annual basis, revenue was US$1,560 million for 2014 compared to US$1,485 million for 2013. The increase was primarily due to an increase in retail customer electricity rates at TEP, effective July 1, 2013, and at UNS Electric, effective January 1, 2014, and higher revenue under the lost fixed-cost recovery mechanism, as approved by the regulator.

Earnings

Earnings were US$54 million from the date of acquisition. On an annual basis, earnings were US$144 million for 2014, compared to US$132 million for 2013, excluding the impact of acquisition-related expenses. The increase was driven by the increase in retail customer electricity rates at TEP and UNS Electric, as discussed above.

Outlook

In the short term, the Corporation is focused on the integration of UNS Energy. The acquisition was immediately accretive to earnings per common share of Fortis, excluding one-time acquisition-related expenses. The allowed ROEs and common equity components of capital structure at the UNS Utilities are set at current levels for the near term, as approved by the regulator. UNS Energy has a long-term energy resource diversification strategy to provide long-term rate stability for customers, mitigate environmental impacts, comply with regulatory requirements and leverage existing utility infrastructure.

CENTRAL HUDSON

Financial Highlights (1)
Years Ended December 31 2014 2013 Variance
Average US:CDN Exchange Rate (2) 1.10 1.04 0.06
Electricity Sales (GWh) 5,075 2,629 2,446
Gas Volumes (PJ) 23 9 14
Revenue ($ millions) 821 335 486
Earnings ($ millions) 37 23 14
(1) Financial results of Central Hudson are from June 27, 2013, the date of acquisition.
(2) The reporting currency of Central Hudson is the US dollar.

Electricity Sales & Gas Volumes

Electricity sales were 5,075 GWh for 2014 compared to 5,159 GWh for the full year in 2013. The decrease was mainly due to lower average consumption in the second half of 2014 as a result of cooler temperatures, which reduced the use of air conditioning and other cooling equipment. The decrease was partially offset by higher average consumption in the first quarter of 2014 due to colder temperatures.

Gas volumes of 23 PJ for 2014 were comparable with the full year in 2013.

Revenue

Revenue was US$743 million for 2014 compared to US$668 million for the full year in 2013. The increase was primarily due to the recovery from customers of overall higher commodity costs, which were driven by higher wholesale prices. Foreign exchange associated with the translation of US dollar-denominated revenue also had a favourable impact on revenue.

Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on revenue and earnings.

Earnings

Earnings were US$34 million for 2014 compared to US$44 million for the full year in 2013. The decrease was primarily due to the impact of higher depreciation and operating expenses during the two-year rate freeze period post acquisition beginning in June 2013. Operating expenses for 2014 were unfavourably impacted by colder temperatures in the first half of the year, resulting in higher restoration and employee-related expenses, and an increase in bad debt expense. This decrease was partially offset by the impact of US$2 million in expenses recognized in the first quarter of 2013 as a result of a regulatory order denying the deferral of certain storm-restoration costs.

Outlook

In July 2014 Central Hudson filed a General Rate Application ("GRA") seeking to increase electricity and natural gas delivery rates effective July 1, 2015. This marks the end of the two-year delivery rate freeze that was implemented as part of the regulatory approval of the acquisition of Central Hudson in June 2013. Over the same two-year delivery rate freeze period, Central Hudson will have invested US$215 million in capital expenditures. A Joint Settlement Proposal was filed in February 2015 that provides for new rates at Central Hudson for a three-year period beginning July 1, 2015.

REGULATED GAS UTILITIES - CANADIAN

Regulated Gas Utilities - Canadian earnings for 2014 were $127 million (2013 - $127 million), which represented approximately 28% of the Corporation's total regulated earnings (2013 - 32%). Total segment assets were approximately $5.8 billion as at December 31, 2014 (December 31, 2013 - $5.5 billion), which represented approximately 23% of the Corporation's total regulated assets as at December 31, 2014 (December 31, 2013 - 34%).

A graph is available at the following address: http://media3.marketwire.com/docs/RegulatedGasUtilities2.pdf

FORTISBC ENERGY COMPANIES

Financial Highlights
Years Ended December 31 2014 2013 Variance
Gas Volumes (PJ) 195 200 (5 )
Revenue ($ millions) 1,435 1,378 57
Earnings ($ millions) 127 127 -

Gas Volumes

The decrease in gas volumes was mainly due to lower average consumption as a result of changes in weather. Lower average consumption in the fourth quarter of 2014 due to warmer temperatures was partially offset by higher average consumption in the first quarter of 2014 due to colder temperatures.

As at December 31, 2014, the total number of customers served by the FortisBC Energy companies was approximately 967,000, up 11,000 customers from December 31, 2013.

The FortisBC Energy companies earn approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulatory deferral mechanisms, changes in consumption levels and the cost of natural gas from those forecast to set customer gas rates do not materially affect earnings.

Revenue

The increase in revenue was primarily due to a higher commodity cost of natural gas charged to customers and an increase in the delivery component of customer rates, effective January 1, 2014. The increase was partially offset by lower gas volumes.

Earnings

Earnings were comparable with 2013. The outcome of the second stage of the Generic Cost of Capital ("GCOC") Proceeding in British Columbia, as discussed below, had a slightly favourable impact on earnings in 2014, combined with higher allowance for funds used during construction ("AFUDC"). These impacts were largely offset by the impact of regulatory flow-through deferrals and the earnings sharing mechanism under PBR regulation, which commenced effective January 1, 2014.

In March 2014 the regulatory decision on the second stage of the GCOC Proceeding in British Columbia was received, resulting in an increase in the allowed ROE at FEWI and an increase in the common equity component of capital structure at FEWI and FEVI, effective January 1, 2013. The cumulative impact of this regulatory decision was recognized in 2014, when the decision was received. For further details on the GCOC Proceeding, refer to the "Material Regulatory Decisions and Applications" section of the MD&A.

Outlook

FEI is entering the second year under its 6-year PBR Plan, as approved by the regulator. The Company remains focused on achieving productivity improvements throughout the PBR term. In October 2014 FEI started construction of its Tilbury Expansion in British Columbia. The Tilbury Expansion is estimated to cost approximately $400 million and will include a second LNG tank and a new liquefier, both to be in service by the end of 2016. FEI is also pursuing additional natural gas investment opportunities, including further expansion of the Tilbury LNG facility.

REGULATED ELECTRIC UTILITIES - CANADIAN

Regulated Electric Utilities - Canadian earnings for 2014 were $209 million (2013 - $219 million), which represented approximately 45% of the Corporation's total regulated earnings (2013 - 56%). Total segment assets were approximately $7.8 billion as at December 31, 2014 (December 31, 2013 - $7.5 billion), which represented approximately 32% of the Corporation's total regulated assets as at December 31, 2014 (December 31, 2013 - 47%).

A graph is available at the following address: http://media3.marketwire.com/docs/RegulatedElectricUtilities_Canadian.pdf

FORTISALBERTA

Financial Highlights
Years Ended December 31 2014 2013 Variance
Energy Deliveries (GWh) 17,372 16,934 438
Revenue ($ millions) 518 475 43
Earnings ($ millions) 103 94 9

Energy Deliveries

The increase in energy deliveries was driven by growth in the number of customers. The total number of customers increased by approximately 12,000 year over year, as a result of economic growth in the province of Alberta. Higher average consumption by residential and commercial customers also contributed to the increase, mainly due to changes in temperatures.

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. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.

Revenue

The increase in revenue was primarily due to an interim increase in customer distribution rates, effective January 1, 2014, growth in the number of customers and an increase in revenue related to flow-through costs to customers. The increase in revenue was partially offset by lower net transmission revenue, of which approximately $2 million was recognized in the first quarter of 2013 associated with the finalization of 2012 net transmission volume variances.

Earnings

The increase in earnings was mainly due to rate base growth, an increase in the number of customers, higher income tax recoveries and the impact of approximately $1.5 million in restoration costs recognized in 2013 related to flooding in southern Alberta. The increase in earnings was partially offset by lower net transmission revenue, as discussed above.

Earnings associated with rate base growth continued to be tempered by the interim regulatory decision granting 60% of the revenue requirement associated with the capital tracker component of the PBR mechanism.

Outlook

Significant regulatory uncertainty remains for utilities in Alberta related to the outcome of several regulatory proceedings. FortisAlberta has a final decision pending on its combined capital tracker application for 2013 through 2015. In December 2014, the regulator approved, on an interim basis, customer distribution rates for 2015 based on 90% of the applied for capital tracker amounts, as compared to 60% approved on an interim basis for 2013 and 2014. FortisAlberta's final allowed ROE and capital structure for 2013 through 2015 are also to be determined, subject to the outcome of the GCOC Proceeding in Alberta, which is also expected in the first quarter of 2015.

FORTISBC ELECTRIC

Financial Highlights
Years Ended December 31 2014 2013 Variance
Electricity Sales (GWh) 3,179 3,211 (32 )
Revenue ($ millions) 334 317 17
Earnings ($ millions) 46 50 (4 )

Electricity Sales

The decrease in electricity sales was mainly due to lower average consumption as a result of changes in weather compared to last year. Lower average consumption in the fourth quarter of 2014 due to warmer temperatures was partially offset by higher average consumption in the first quarter of 2014 due to colder temperatures.

Revenue

The increase in revenue was primarily due to an increase in base electricity rates, effective January 1, 2014, and higher flow-through adjustments owing to customers, partially offset by lower electricity sales.

Earnings

The decrease in earnings was primarily due to the impact of lower-than-expected finance charges in 2013, which were not subject to regulatory deferral mechanisms in that year. Effective January 1, 2014, variances in finance charges from those used to establish customer rates are subject to regulatory deferral mechanisms and did not impact earnings in 2014.

Outlook

FortisBC Electric is entering the second year under its 6-year PBR Plan, as approved by the regulator. The Company remains focused on achieving productivity improvements throughout the PBR term.

EASTERN CANADIAN ELECTRIC UTILITIES

Financial Highlights
Years Ended December 31 2014 2013 Variance
Electricity Sales (GWh) 8,376 8,168 208
Revenue ($ millions) 1,008 975 33
Earnings ($ millions) 60 75 (15 )

Electricity Sales

The increase in electricity sales was primarily due to customer growth in Newfoundland and PEI, including an increase in the number of customers using electricity for home heating, and higher average consumption by residential and commercial customers in all regions, due to colder temperatures in the first half of 2014.

Revenue

The increase in revenue was driven by electricity sales growth and an increase in base electricity rates at Newfoundland Power, effective July 1, 2013. The increase was partially offset by the flow through in customer electricity rates of lower energy supply costs at FortisOntario.

Earnings

The decrease in earnings was mainly due to income tax recoveries recognized in 2013 of approximately $13 million at Newfoundland Power and $4 million at Maritime Electric, due to the enactment of higher deductions associated with Part VI.1 tax. Excluding the $17 million income tax recovery, earnings increased by $2 million in 2014 compared to last year. The impact of electricity sales growth was partially offset by higher operating costs at Newfoundland Power associated with restoration efforts following the loss of energy supply from Newfoundland and Labrador Hydro ("Newfoundland Hydro") and related power interruptions in January 2014.

Outlook

Allowed ROEs and capital structures at Eastern Canadian Electric Utilities for 2015 remain substantially unchanged from 2014. Newfoundland Power is required to file a GRA in the first half of 2015 to establish customer rates for 2016.

REGULATED ELECTRIC UTILITIES - CARIBBEAN

Regulated Electric Utilities - Caribbean earnings for 2014 were $27 million (2013 - $23 million), which represented approximately 6% of the Corporation's total regulated earnings (2013 - 6%). Total segment assets were approximately $1.0 billion as at December 31, 2014 (December 31, 2013 - $0.8 billion), which represented approximately 4% of the Corporation's total regulated assets as at December 31, 2014 (December 31, 2013 - 5%).

A graph is available at the following address: http://media3.marketwire.com/docs/RegulatedElectricUtilities_Caribbean.pdf

Financial Highlights
Years Ended December 31 2014 2013 Variance
Average US:CDN Exchange Rate (1) 1.10 1.03 0.07
Electricity Sales (GWh) 771 749 22
Revenue ($ millions) 321 290 31
Earnings ($ millions) 27 23 4
(1) The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar.

Electricity Sales

The increase in electricity sales was driven by growth in the number of customers and increases in tourism. Warmer temperatures in the Turks and Caicos Islands, which increased air conditioning load, also contributed to the increase in electricity sales.

Revenue

The increase in revenue was primarily due to approximately $21 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, due to the strengthening of the US dollar relative to the Canadian dollar year over year. Electricity sales growth and an increase in base customer electricity rates at Caribbean Utilities also favourably impacted revenue year over year.

Earnings

The increase in earnings was primarily due to electricity sales growth and approximately $1.5 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by higher operating expenses.

Outlook

Economic conditions in the Caribbean region continue to show signs of improvement. Electricity sales at Caribbean Utilities and Fortis Turks and Caicos are expected to increase in 2015, reflecting general projected increases in economic activity in the Cayman Islands and the continuation of local development projects in the Turks and Caicos Islands, respectively. For further information, refer to the "Business Risk Management - Economic Conditions" section of this MD&A.

NON-REGULATED

NON-REGULATED - FORTIS GENERATION

Financial Highlights
Years Ended December 31 2014 2013 Variance
Energy Sales (GWh) 407 386 21
Revenue ($ millions) 38 35 3
Earnings ($ millions) 20 39 (19 )

A graph is available at the following address: http://media3.marketwire.com/docs/NonRegulatedFortisGeneration.pdf

Energy Sales

The increase in energy sales was due to increased production in Upstate New York due to a generating unit being returned to service in October 2013. Production in Belize was comparable year over year.

Revenue

The increase in revenue was primarily due to approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue and higher production in Upstate New York.

Earnings

The decrease in earnings was primarily due to the recognition of an approximate $20 million after-tax extraordinary gain on the settlement of expropriation matters associated with the Exploits Partnership in 2013. Excluding the $20 million extraordinary gain, earnings increased by $1 million. The increase was primarily due to approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings and higher production in Upstate New York. The increase was partially offset by approximately $2 million in business development costs associated with investigating a potential hydroelectric generating facility in British Columbia.

Outlook

Construction of the non-regulated Waneta Expansion in British Columbia is expected to be completed in spring 2015. This will significantly increase annual earnings from the Non-Regulated - Fortis Generation segment.

NON-REGULATED - NON-UTILITY

Financial Highlights (1)
Years Ended December 31
($ millions) 2014 2013 Variance
Revenue 249 248 1
Earnings 28 18 10
(1) Comprised of Fortis Properties and Griffith. Griffith was acquired in June 2013 as part of the acquisition of Central Hudson and was sold in March 2014. As such, the results of operations of Griffith have been presented as discontinued operations on the consolidated statements of earnings and, accordingly, revenue excludes amounts associated with Griffith. Earnings, however, reflect the financial results of Griffith from June 2013 to March 2014.

A graph is available at the following address: http://media3.marketwire.com/docs/NonRegulatedNonUtility.pdf

Revenue

Revenue at Fortis Properties was comparable to last year.

Earnings

Earnings at Fortis Properties were approximately $23 million for 2014, comparable to last year.

Earnings for 2014 include $5 million associated with Griffith from normal operations to the date of sale in March 2014. Earnings for 2013 include a net loss of approximately $5 million associated with Griffith, which reflected deferred tax expenses of $3.5 million associated with the derecognition of a combined filing tax benefit, due to the sale of Griffith.

Outlook

In September 2014 the Corporation announced that it would engage in a review of strategic options for its hotel and commercial real estate business. For further details, refer to the "Significant Items - Review of Strategic Options for Fortis Properties" section of this MD&A.

CORPORATE AND OTHER

Financial Highlights
Years Ended December 31
($ millions) 2014 2013 Variance
Revenue 31 26 5
Operating Expenses 38 13 25
Depreciation and Amortization 2 2 -
Other Income (Expenses), Net (45 ) (45 ) -
Finance Charges 154 48 106
Income Tax Recovery (79 ) (43 ) (36 )
(129 ) (39 ) (90 )
Preference Share Dividends 62 57 5
Net Corporate and Other Expenses (191 ) (96 ) (95 )

Net Corporate and Other expenses were significantly impacted by the following items.

  1. Finance charges of $72 million ($51 million after tax) associated with the Convertible Debentures issued in 2014 to finance a portion of the acquisition of UNS Energy, including the expense associated with the make-whole payment;
  2. Other expenses of approximately $33 million (US$30 million), or $20 million (US$18 million) after tax, associated with customer benefits offered by the Corporation to close the acquisition of UNS Energy, compared to approximately $41 million (US$ 40 million), or $26 million (US$26 million) after tax, associated with customer and community benefits offered by the Corporation to close the acquisition of Central Hudson in 2013;
  3. Other expenses of $25 million ($19 million after tax) in 2014 related to the acquisition of UNS Energy, compared to approximately $12 million ($8 million after tax) in 2013 related to the acquisition of Central Hudson;
  4. A foreign exchange gain of $8 million in 2014 compared to a foreign exchange gain of $6 million in 2013, associated with the Corporation's US dollar-denominated long-term other asset, representing the book value of the Corporation's expropriated investment in Belize Electricity, which was included in other income, net of expenses;
  5. Retirement expenses of approximately $13 million ($11 million after tax) in 2014, which were included in operating expenses;
  6. A $6 million income tax recovery in 2013, due to the enactment of higher deductions associated with Part VI.1 tax; and
  7. The release of income tax provisions of approximately $7 million in 2013.

Excluding the above-noted items, net Corporate and Other expenses were $98 million for 2014 compared to approximately $81 million for 2013. The increase was primarily due to higher finance charges, preference share dividends and operating expenses, partially offset by a higher income tax recovery and interest income.

The increase in finance charges was primarily due to the acquisition of UNS Energy in August 2014 and Central Hudson in June 2013. Finance charges were also impacted by unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense. The increase was partially offset by higher capitalized interest associated with the financing of the construction of the non-regulated Waneta Expansion.

Higher preference share dividends were largely due to the issuance of First Preference Shares, Series M in September 2014 used to finance a portion of the acquisition of UNS Energy.

The increase in operating expenses was mainly due to higher share-based compensation expenses, as a result of share price appreciation, legal and consulting fees, and general inflationary increases.

REGULATORY HIGHLIGHTS

The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated electric and gas utilities are summarized as follows.

NATURE OF REGULATION







Allowed Returns (%)

Significant Features
Regulated
Utility

Regulatory
Authority

Allowed
Common
Equity

(%)


2013

2014

2015
Future or Historical Test Year
Used to Set Customer Rates
ROE
TEP ACC 43.5 10.13(1) 10.00(1) 10.00(1) COS/ROE
UNS Electric ACC 52.6 9.75(1) 9.50(1) 9.50(1) ROEs established by the ACC
UNS Gas ACC 50.8 9.75(1) 9.75(1) 9.75(1)
Historical Test Year
Central New York State 48 10.00 10.00 9.50(2) COS/ROE
Hudson Public Service
Commission ("PSC") Earnings sharing mechanism
effective July 1, 2013
ROE established by the PSC
Future Test Year
FEI British Columbia 38.5 8.75 8.75 8.75 COS/ROE
Utilities Commission
("BCUC") FEI - PBR mechanism for 2014
through 2019
FEVI BCUC 41.5(3) 9.25 9.25 n/a(3)
ROEs established by the BCUC
FEWI BCUC 41.5(3) 9.50 9.50 n/a(3)
2013 test year with 2014 through 2019
rates set using PBR mechanism
FortisBC BCUC 40 9.15 9.15 9.15 COS/ROE
Electric
PBR mechanism for 2014 through 2019
ROE established by the BCUC
2013 test year with 2014 through 2019
rates set using PBR mechanism
Fortis-
Alberta
Alberta Utilities 41(4) 8.75(4) 8.75(4) 8.75(4) COS/ROE
Commission ("AUC")
PBR mechanism for 2013 through
2017 with capital tracker account
and other supportive features
ROE established by the AUC
2012 test year with 2013 through
2017 rates set using PBR mechanism
Newfound-
land
Newfoundland and 45 8.80 +/- 8.80 +/- 8.80 +/- COS/ROE
Power Labrador Board of 50 bps 50 bps 50 bps
Commissioners of ROE established by the PUB
Public Utilities
("PUB") Future Test Year
Maritime Island Regulatory 40 9.75 9.75 9.75 COS/ROE
Electric and Appeals
Commission ROE established by the Government of
PEI under the PEI Energy Accord
Future Test Year
Fortis-
Ontario
Ontario Energy 40 8.93 - 8.93 - 8.93 - COS/ROE (5)
Board 9.85 9.85 9.30 Future test year and incentive
rate-setting mechanism
ROA
Caribbean Electricity N/A 6.50 - 7.00 - 7.00 - COS/ROA
Utilities Regulatory 8.50 9.00 9.00
Authority Rate-cap adjustment mechanism
based on published consumer
price indices
Historical Test Year
Fortis Turks Government of the N/A 15.00 - 15.00 - 15.00 - COS/ROA
and Caicos Turks and Caicos 17.50 (6) 17.50 (6) 17.50 (6)
Islands Historical Test Year
(1) Additionally, allowed ROEs are adjusted for the fair value of rate base as required under the laws of the State of Arizona.
(2) Allowed ROE of 10.0% with a 48% common equity component of capital structure to June 30, 2015. Allowed ROE of 9.00% with a 48% common equity component of capital structure effective July 1, 2015 as filed by Central Hudson in its February 2015 Joint Settlement Proposal and is subject to regulatory approval.
(3) Effective December 31, 2014, FEVI and FEWI were amalgamated with FEI and, as a result, the allowed ROE and common equity component of capital structure for the amalgamated entity in 2015 will be set the same as FEI.
(4) Common equity component of capital structure and allowed ROE for 2013, 2014 and 2015 are interim and are subject to change based on the outcome of a cost of capital proceeding.
(5) Cornwall Electric is subject to a rate-setting mechanism under a Franchise Agreement with the City of Cornwall, based on a price cap with commodity cost flow through.
(6) Achieved ROAs at the utilities are significantly lower than those allowed under licences as a result of the inability, due to economic and political factors, to increase base customer electricity rates.

MATERIAL REGULATORY DECISIONS AND APPLICATIONS

The following summarizes the significant regulatory decisions and applications for the Corporation's largest regulated utilities for 2014.

UNS Energy

In August 2014 the ACC approved the acquisition of UNS Energy by Fortis. As part of the regulatory approval required in connection with the acquisition, Fortis committed to provide UNS Energy's customers with certain benefits: (i) providing the retail consumers of the UNS Utilities with bill credits totalling US$30 million over five years (US$10 million in year one and US$5 million annually in years two through five); (ii) UNS Energy and the UNS Utilities adopting certain ring-fencing and corporate governance provisions; (iii) limiting dividends paid from the UNS Utilities to UNS Energy to 60% of the UNS Utilities' respective net income for the earlier of five years or until such time that their respective equity capitalization reaches 50% of total capital as accounted for in accordance with US GAAP; and (iv) Fortis making an equity infusion totalling US$220 million through UNS Energy into the UNS Utilities after the closing of the acquisition, which was completed within 60 days of the acquisition.

There were no significant regulatory decisions and applications at UNS Energy from the date of acquisition.

Central Hudson

In July 2014 Central Hudson filed a GRA seeking to increase electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through to June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson committed to invest US$215 million in capital expenditures during the two-year delivery rate freeze period ending June 30, 2015. In its GRA, the Company requested an allowed ROE of 9.0% with a 48% common equity component of capital structure for a term of one year. The current rate order includes an allowed ROE of 10.0% with a 48% common equity component of capital structure. A Joint Settlement Proposal was filed in February 2015 that provides for new rates at Central Hudson for a three-year period beginning July 1, 2015, reflecting an allowed ROE of 9.0% and a 48% common equity component of capital structure. The Joint Settlement Proposal includes continuation of certain mechanisms currently in place, including revenue decoupling and earnings sharing mechanisms. Under the proposed earnings sharing mechanism, the Company and customers share equally earnings in excess of 50 basis points above the allowed ROE up to an achieved ROE that is 100 basis points above the allowed ROE. Public statement hearings are expected to be held in March or April with the Joint Settlement Proposal targeted to go to the regulator in June for consideration and approval.

In April 2014 the PSC issued an order instituting a proceeding Reforming the Energy Vision to reform New York State's energy industry and regulatory practices. The initiative will seek to further a number of policy objectives and seek to determine the appropriate role of distribution utilities in furthering these objectives, as well as considering regulatory changes to better align utility interest with energy policy objectives. The outcome of this proceeding cannot be determined at this time and it could impact the scope of regulated utilities in New York State.

FortisBC Energy Companies and FortisBC Electric

In February 2014 the FortisBC Energy companies received regulatory approval for the amalgamation of its regulated utilities. The regulator approved the adoption of common rates for the majority of natural gas customers, to be phased in over a three-year period. The amalgamation received the consent of the Lieutenant Governor in Council in May 2014 and was effected on December 31, 2014.

In May 2013 the BCUC issued its decision on the first stage of the GCOC Proceeding in British Columbia. Effective January 1, 2013, the decision set the allowed ROE of the benchmark utility, FEI, at 8.75% with a 38.5% common equity component of capital structure. The common equity component of capital structure will remain in effect until December 31, 2015. Effective January 1, 2014 through December 31, 2015, the BCUC has also introduced an Automatic Adjustment Mechanism ("AAM") to set the allowed ROE for the benchmark utility on an annual basis. The AAM will take effect when the long-term Government of Canada bond yield exceeds 3.8%. In January and December 2014, the BCUC confirmed that the necessary conditions for the AAM to be triggered for the 2014 and 2015 allowed ROE have not been met; therefore, the benchmark allowed ROE remains at 8.75% for 2015. FEVI, FEWI and FortisBC Electric's allowed ROEs and common equity component of capital structures were determined in the second stage of the GCOC Proceeding. However, as a result of the decision on the first stage of the GCOC Proceeding, which reduced the allowed ROE of the benchmark utility by 75 basis points, the interim allowed ROEs for FEVI, FEWI and FortisBC Electric decreased to 9.25%, 9.25% and 9.15%, respectively, effective January 1, 2013, while the deemed common equity component of capital structures remained unchanged.

In March 2014 the BCUC issued its decision on the second stage of the GCOC Proceeding. Effective January 1, 2013, the decision set the common equity component of capital structure for FEVI and FEWI at 41.5%, and reaffirmed the common equity component of capital structure for FortisBC Electric at 40%. The BCUC reaffirmed for FEVI and FortisBC Electric a risk premium over the benchmark utility of 50 basis points and 40 basis points, respectively, and set FEWI's equity risk premium at 75 basis points, which represented an increase of 25 basis points. The resulting allowed ROEs, effective January 1, 2013, for FEVI, FEWI and FortisBC Electric are 9.25%, 9.50% and 9.15%, respectively. The cumulative impact of the outcome of the second stage of the GCOC Proceeding was recognized in the first quarter of 2014 and did not have a material impact on earnings.

Effective January 1, 2015, the allowed ROE and common equity component of capital structure for the amalgamated entity FEI will be set at 8.75% and 38.5%, respectively, which is the benchmark utility. The GCOC Proceeding has directed FEI to file an application for the review of the allowed ROE and the common equity component of capital structure no later than November 30, 2015 to determine the benchmark for 2016.

In September 2014 the BCUC issued its decisions on FEI's and FortisBC Electric's Multi-Year PBR Plans for 2014 through 2018. As part of the PBR decisions, the terms were extended to 2019. The approved PBR Plans incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FEI and 1.03% for FortisBC Electric each year. The approved PBR Plans also include a 50%/50% sharing of variances from the formula-driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FEI and FortisBC Electric maintain service levels. It also sets out the requirements for an annual review process which will provide a forum for discussion between the utilities and interested parties regarding current performance and future activities.

In October and November 2014, FEI and FortisBC Electric filed Compliance Filings with the BCUC which updated the 2014 revenue requirements and rates based on the PBR decisions. FEI and FortisBC Electric's Compliance Filings updated the midyear rate base to approximately $2,765 million and $1,204 million, respectively, and the delivery rate increase for FEI to 1.8%, up from 1.4% previously approved on an interim basis, and FortisBC Electric to 3.3%, as previously approved on an interim basis.

In November 2013 the Government of British Columbia issued an Order of the Lieutenant Governor in Council ("Order in Council") directing the BCUC to allow the FortisBC Energy companies to expand their Tilbury LNG Facility Expansion. The Order in Council set out a number of requirements, including exempting the Tilbury Expansion from a Certificate of Public Convenience and Necessity ("CPCN") process, imposing an upper limit of $400 million on the capital cost of the project, and allowing for the recovery of the costs of the Tilbury Expansion from customers. In December 2014 the Government of British Columbia issued a second Order in Council amending directions to the BCUC. The revised Order in Council set out a number of requirements for the BCUC including: (i) allowing the Tilbury Expansion to proceed in two phases (Phase 1A and Phase 1B), with Phase 1B proceeding if the FortisBC Energy companies obtain long-term sales contracts taking a minimum of 70% of the liquefaction capacity of Phase 1B, on average, for the first 15 years of its operation; (ii) imposing an upper limit of $400 million of direct capital costs on each phase of the Tilbury Expansion; (iii) exempting from a CPCN process the pipeline and compression facilities that would supply a third-party operated LNG facility near Squamish, British Columbia, should it proceed; and (iv) exempting from a CPCN process the Coastal Transmission System projects, which consist of four transmission line projects, three of which increase the Companies' pipeline capacity within the Lower Mainland and one to increase the capacity to the Tilbury LNG Facility.

In compliance with the recent PBR decisions, in January and February 2015 FEI and FortisBC Electric, respectively, filed for approval of their 2015 rates under the PBR decision. The applications assume a forecast midyear rate base of approximately $3,656 million and $1,267 million for FEI and FortisBC Electric, respectively, and request approval of customer rate increases of approximately 2.0% and 4.6% over 2014 rates, respectively, determined under a formula approach for operating and maintenance costs and capital costs. The regulatory process to review the applications will continue through 2015, with a decision on the final rate increases expected in the second quarter of 2015.

FortisAlberta

In May 2014 FortisAlberta filed a combined 2013, 2014 and 2015 Capital Tracker Application as required by the regulator, which requested capital tracker revenue of approximately $23 million for 2013, $48 million for 2014 and $69 million for 2015. Capital tracker revenue for each of the three years will be subject to change based on the categories to be approved for capital tracker treatment by the regulator, the actual cost of debt used to finance the capital expenditures, and the final allowed ROE and capital structure to be determined in the GCOC proceeding. Capital tracker revenue for 2014 and 2015 will also be subject to change based on the true-up to actual capital expenditures. For 2013 and 2014, FortisAlberta recognized capital tracker revenue of approximately $15 million and $30 million, respectively, based on the interim regulatory decision granting 60% of the applied for capital tracker amounts. A hearing related to the combined Capital Tracker Application was held in October 2014 and a decision is expected in the first quarter of 2015. Any adjustment by the regulator to the interim decision for 2013 and 2014 will result in an adjustment to FortisAlberta's revenue. Such an adjustment would be recognized in the consolidated financial statements when the regulatory decision is received, or when sufficient information is available to reasonably estimate the required adjustment in accordance with US GAAP.

In December 2014 the AUC approved FortisAlberta's 2015 Annual Rates Application on an interim basis. The rates and riders, effective January 1, 2015, include an increase of approximately 8.5% to the distribution component of customer rates. This increase reflects a combined inflation and productivity factor of 1.49%, a K factor placeholder of approximately $62 million, which is 90% of the 2015 capital tracker revenue applied for in the May 2014 Capital Tracker Application, and a net refund of Y factor balances of approximately $1 million. The rates will remain interim until a final decision is received regarding the combined Capital Tracker Application.

A hearing related to the GCOC proceeding in Alberta concluded in June 2014, with supplemental submissions filed in November 2014. The AUC is expected to set the allowed ROE and capital structure for utilities in Alberta for 2013, 2014 and possibly for 2015. The AUC will also consider re-establishing a formula-based approach to setting the allowed ROE going forward. A decision on this proceeding is expected in the first quarter of 2015.

Caribbean Utilities

In October 2014 the ERA announced that Caribbean Utilities was the successful bidder for new generation capacity on Grand Cayman. Caribbean Utilities will develop and operate a new 39.7 MW diesel power plant, including two 18.5 MW diesel generating units and a 2.7 MW waste heat recovery steam turbine. The project cost is estimated at US$85 million and the plant is expected to be commissioned no later than June 2016. Subsequently, in November 2014 the ERA issued a new non-exclusive Electricity Generation Licence to Caribbean Utilities for a term of 25 years, expiring in November 2039.

Significant Regulatory Proceedings

The following table summarizes ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's largest regulated utilities.

Regulated Utility Application/Proceeding Filing Date Expected Decision
Central Hudson General Rate Application for mid-2015 July 2014 First half of 2015
FortisAlberta GCOC Proceeding Not applicable First quarter of 2015
Capital Tracker Applications -
2013, 2014 and 2015 May 2014 First quarter of 2015

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between December 31, 2014 and December 31, 2013.

Significant Changes in the Consolidated Balance Sheets between December 31, 2014 and December 31, 2013




Balance Sheet Account
Increase
Due to
UNS Energy
($ millions)
Other
Increase/
(Decrease)
($ millions)



Explanation for Other Increase/(Decrease)
Cash and cash equivalents 122
36
The increase in cash and cash equivalents was not
significant.
Accounts receivable and other current assets 214
(46)
The decrease in accounts receivable and other current assets was not significant.
Inventories 160 18 The increase in inventories was not significant.
Regulatory assets - current and long-term 392




311




The increase was mainly due to: (i) an increase in the employee future benefits deferral due to higher defined benefit pension and other post-employment benefits ("OPEBs") plan
liabilities; (ii) an increase in the manufactured gas plant site remediation deferral at Central Hudson; (iii) an increase in regulatory deferred income taxes; and (iv) the deferral of various other costs as permitted by the regulators.
Assets held for sale - (112) The decrease related to the sale of Griffith in March 2014.
Deferred income tax assets - current and long-term 127
44
The increase in deferred income tax assets was not significant.
Other assets 76 15 The increase in other assets was not significant.
Utility capital assets 4,608
926
The increase primarily related to utility capital expenditures and the impact of foreign exchange on the translation of US dollar-denominated utility capital assets, partially offset by depreciation and customer contributions.
Intangible assets 140 3 The increase in intangible assets was not significant.
Goodwill 1,603 54 The increase was primarily due to the impact of foreign exchange on the translation of US dollar-denominated goodwill.
Short-term borrowings - 170 The increase was driven by short-term borrowings at the FortisBC Energy companies to finance utility capital expenditures.
Accounts payable and other current liabilities 353 130 The increase was mainly due to higher trade accounts payable associated with capital accruals, and higher dividends payable, driven by an increase in the number of common shares outstanding.
Regulatory liabilities - current and long-term 512 1 The increase in regulatory liabilities was not significant.
Long-term debt (including current portion) 2,080
1,217

The increase was driven by the issuance of long-term debt, higher net credit facility borrowings, mainly at the Corporation to finance a portion of the acquisition of UNS Energy, and the
impact of foreign exchange on the translation of US-dollar denominated debt. The increase was partially offset by regularly scheduled debt repayments.
Capital lease and finance obligations (including current portion) 283 (4) The decrease in capital lease and finance obligations was not significant.
Deferred income tax liabilities - current and long-term 659 101 The increase was driven by tax timing differences related mainly to capital expenditures at the regulated utilities.
Other liabilities 295 219

The increase was primarily due to an increase in the manufactured gas plant site remediation provision at Central Hudson, and an increase in defined benefit pension and OPEB plan liabilities, mainly due to lower discount rates as at December 31, 2014.
Shareholders' equity (before non-controlling interests) -








2,690









The increase primarily related to: (i) the conversion of Convertible Debentures into common shares for net after-tax proceeds of $1.747 billion; (ii) the issuance of First Preference
Shares, Series M in September 2014 for net after-tax proceeds of $591 million; (iii) net earnings attributable to common equity
shareholders for 2014, less dividends declared on common shares; (iv) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US-dollar denominated investments in subsidiaries, net of hedging activities and tax; and (v) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

The table below outlines the Corporation's sources and uses of cash in 2014 compared to 2013, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows
Years Ended December 31
($ millions) 2014 2013 Variance
Cash, Beginning of Year 72 154 (82 )
Cash Provided by (Used in):
Operating Activities 982 899 83
Investing Activities (4,199 ) (2,164 ) (2,035 )
Financing Activities 3,361 1,186 2,175
Effect of Exchange Rate Changes on
Cash and Cash Equivalents 14 - 14
Less Cash at Discontinued Operations - (3 ) 3
Cash, End of Year 230 72 158

Operating Activities: Cash flow from operating activities in 2014 was $83 million higher than in 2013. The increase was driven by higher cash earnings, partially offset by unfavourable changes in working capital and long-term regulatory deferrals.

A graph is available at the following address: http://media3.marketwire.com/docs/CashFlowFromOperatingActivities.pdf

Investing Activities: Cash used in investing activities in 2014 was $2,035 million higher than in 2013. The increase was due to the acquisition of UNS Energy in August 2014 for a net cash purchase price of $2,745 million, compared to the acquisition of Central Hudson in June 2013 for a net cash purchase price of $1,019 million and FortisBC Electric's acquisition of the electric utility assets from the City of Kelowna in March 2013 for approximately $55 million. Capital expenditures at UNS Energy from the date of acquisition and higher capital spending at the FortisBC Energy companies were partially offset by lower capital expenditures at FortisAlberta and the Waneta Expansion. The increase in cash used in investing activities was partially offset by proceeds of approximately $105 million from the sale of Griffith in March 2014.

Financing Activities: Cash provided by financing activities in 2014 was $2,175 million higher than in 2013. The increase was driven by the financing of the UNS Energy acquisition in 2014, compared to the financing of the Central Hudson acquisition in 2013.

The acquisition of UNS Energy was financed from proceeds of $1,800 million, or $1,725 million net of issue costs, from the issue of Convertible Debentures in January and October 2014, proceeds from the issue of preference shares and credit facility borrowings. In October 2014 substantially all of the Convertible Debentures were converted into 58.2 million common shares of Fortis. The acquisition of Central Hudson was financed from the issuance of common shares, long-term debt and credit facility borrowings.

Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net borrowings (repayments) under committed credit facilities for 2014 and 2013 are summarized in the following tables.

Proceeds from Long-Term Debt, Net of Issue Costs
Years Ended December 31
($ millions) 2014 2013 Variance
Central Hudson (1) 33 49 (16 )
FortisAlberta (2) 274 149 125
FortisBC Electric (3) 198 - 198
Newfoundland Power (4) - 69 (69 )
Caribbean Utilities (5) 57 51 6
Fortis Turks and Caicos (6) 92 - 92
Corporate (7) 539 335 204
Total 1,193 653 540
(1) In March 2014 Central Hudson issued 10-year US$30 million unsecured notes with a floating interest rate of 3-month LIBOR plus 1%. The net proceeds were used to repay maturing long-term debt and for general corporate purposes. In November and December 2013, Central Hudson issued 5-year US$30 million 2.45% and 15-year US$17 million 4.09% unsecured notes, respectively. The net proceeds were used to repay long-term debt and for general corporate purposes.
(2) In September 2014 FortisAlberta issued $275 million senior unsecured debentures in two tranches of 10-year $150 million at 3.30% and 30-year $125 million at 4.11%. The net proceeds were used repay long-term debt, to finance capital expenditures and for general corporate purposes. In September 2013 FortisAlberta issued 30-year $150 million unsecured debentures at 4.85%. The net proceeds were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes.
(3) In October 2014 FortisBC Electric issued 30-year $200 million 4.00% senior unsecured debentures. The net proceeds were used to repay long-term debt and credit facility borrowings.
(4) In November 2013 Newfoundland Power issued 30-year $70 million 4.805% first mortgage sinking fund bonds. The net proceeds were used to repay credit facility borrowings, which were incurred to fund capital expenditures, and for general corporate purposes.
(5) In November 2014 Caribbean Utilities issued a total of US$50 million unsecured notes with terms to maturity ranging from 15 to 32 years and coupon rates ranging from 3.65% to 4.53%. The net proceeds will be used to finance capital expenditures. In May 2013 Caribbean Utilities issued 15-year US$10 million 3.34% and 20-year US$40 million 3.54% unsecured notes. The net proceeds were used to repay short-term borrowings and to finance capital expenditures.
(6) In December 2014 Fortis Turks and Caicos issued 15-year US$80 million 4.75% unsecured notes. The net proceeds were used to repay inter-company loans with a direct subsidiary of Fortis.
(7) In June 2014 the Corporation issued US$213 million unsecured notes with terms to maturity ranging from 5 to 30 years and coupon rates ranging from 2.92% to 4.88%. The weighted average term to maturity is approximately 9 years and the weighted average coupon rate is 3.51%. Net proceeds were used to repay US-dollar denominated borrowings on the Corporation's committed credit facility and for general corporate purposes. In September 2014 the Corporation issued US$287 million unsecured notes with terms to maturity ranging from 7 to 30 years and coupon rates ranging from 3.64% to 5.03%. The weighted average term to maturity is approximately 12 years and the weighted average coupon rate is 4.11%. Net proceeds were used to repay long-term debt and for general corporate purposes. In October 2013 the Corporation issued 10-year US$285 million 3.84% and 30-year US$40 million 5.08% unsecured notes. The net proceeds were used to repay a portion of the Corporation's US dollar-denominated credit facility borrowings incurred to initially finance a portion of the Central Hudson acquisition.
Repayments of Long-Term Debt and Capital Lease and Finance Obligations
Years Ended December 31
($ millions) 2014 2013 Variance
FortisBC Energy Companies (6 ) (28 ) 22
FortisAlberta (200 ) - (200 )
Central Hudson (24 ) (50 ) 26
FortisBC Electric (140 ) (1 ) (139 )
Newfoundland Power (35 ) (5 ) (30 )
Caribbean Utilities (19 ) (20 ) 1
Fortis Properties (22 ) (65 ) 43
Corporate (293 ) - (293 )
Other (4 ) (4 ) -
Total (743 ) (173 ) (570 )
Net Borrowings (Repayments) Under Committed Credit Facilities
Years Ended December 31
($ millions) 2014 2013 Variance
UNS Energy 61 - 61
FortisAlberta 3 20 (17 )
FortisBC Electric (54 ) 44 (98 )
Newfoundland Power 65 (42 ) 107
Corporate 535 162 373
Total 610 184 426

Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility. Borrowings under the Corporation's credit facilities were primarily incurred to finance a portion of the acquisition of UNS Energy in 2014 and Central Hudson in 2013.

Advances of approximately $36 million for 2014 and $59 million for 2013 were received from non-controlling interests in the Waneta Partnership to finance capital spending related to the Waneta Expansion.

Proceeds from the issuance of common shares were $51 million for 2014 compared to $596 million for 2013. The decrease was primarily due to the issuance of 18.5 million common shares, as a result of the conversion of the Subscription Receipts on closing of the acquisition of Central Hudson in June 2013 for proceeds of approximately $567 million, net of after-tax expenses.

In September 2014 Fortis issued 24 million First Preference shares, Series M for gross proceeds of $600 million. The net proceeds were used to repay a portion of credit facility borrowings used to initially finance a portion of the acquisition of UNS Energy.

In July 2013 Fortis issued 10 million First Preference Shares, Series K for gross proceeds of $250 million. The net proceeds were used to redeem all of the Corporation's First Preference Shares, Series C in July 2013 for $125 million, to repay a portion of credit facility borrowings and for other general corporate purposes.

Common share dividends paid in 2014 totalled $194 million, net of $81 million of dividends reinvested, compared to $181 million, net of $70 million of dividends reinvested, paid in 2013. The increase in dividends paid was due to a higher annual dividend paid per common share and an increase in the number of common shares outstanding. The dividend paid per common share was $1.28 in 2014 compared to $1.24 in 2013. The weighted average number of common shares outstanding was 225.6 million for 2014 compared to 202.5 million for 2013.

CONTRACTUAL OBLIGATIONS

The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at December 31, 2014, are outlined in the following table.

Contractual Obligations
As at December 31, 2014
($ millions)


Total
Due
within
1 year

Due in
year 2

Due in
year 3

Due in
year 4

Due in
year 5
Due
after
5 years
Long-term debt 10,501 505 747 103 741 201 8,204
Interest obligations on long-term debt 8,838 497 475 449 444 432 6,541
Capital lease and finance obligations (1) 2,720 264 67 69 62 90 2,168
Renewable power purchase obligations (2) 1,031 59 59 59 59 59 736
Long-term contracts - UNS Energy (3) 929 121 122 117 85 83 401
Power purchase obligations (4) 891 243 161 128 101 76 182
Capital cost (5) 518 19 22 19 21 19 418
Gas purchase obligations (6) 314 235 20 16 11 9 23
Renewable energy credit purchase agreements (7) 146 11 11 11 11 11 91
Purchase of Springerville common facilities (8) 123 - - 44 - - 79
Defined benefit pension funding contributions (9) 182 77 36 7 8 8 46
Operating lease obligations (10) 152 11 10 9 8 8 106
Waneta Partnership promissory note (11) 72 - - - - - 72
Joint-use asset and shared service agreements (12) 53 3 3 3 3 3 38
Other (13) 72 12 11 10 - 3 36
Total 26,542 2,057 1,744 1,044 1,554 1,002 19,141
(1) Includes principal payments, imputed interest and executory costs, mainly related to UNS Energy's and FortisBC Electric's capital lease obligations.
(2) UNS Energy is party to 20-year long-term renewable power purchase agreements totalling approximately US$888 million as at December 31, 2014, which require UNS Energy to purchase 100% of the output of certain renewable energy generating facilities that have achieved commercial operation. These agreements have various expiry dates through 2034. UNS Energy has entered into additional long-term renewable power purchase agreements to comply with Renewable Energy Standards of the State of Arizona; however, the Company's obligation to purchase power under these agreements does not begin until the facilities are operational.
(3) UNS Energy has entered into various long-term contracts for the purchase and delivery of coal to fuel its generating facilities, the purchase of gas transportation services to meet its load requirements, and the purchase of transmission services for purchased power, with obligations totalling US$510 million, US$215 million and US$75 million, respectively, as at December 31, 2014. Amounts paid under contracts for the purchase and delivery of coal depends on actual quantities purchased and delivered. Certain of these contracts also have price adjustment clauses that will affect future costs under the contracts.
(4) Power purchase obligations include various power purchase contracts held by certain of the Corporation's subsidiaries, mainly Central Hudson, FortisBC Electric and FortisOntario, with obligations totalling US$162 million, $311 million, and $259 million, respectively.
Central Hudson
Central Hudson meets its capacity and electricity obligations through contracts with capacity and energy providers, purchases from the New York Independent System Operator energy and capacity markets, and its own generating capacity. In 2014 Central Hudson entered into two agreements to purchase electricity on a unit-contingent basis at defined prices from December 2014 through March 2015. These contracts replaced existing contracts which expired at the end of 2013.
In June 2014 Central Hudson entered into a contract to purchase available installed capacity from the Danskammer Generating Facility from October 2014 through August 2018 with approximately US$91 million in purchase commitments remaining as at December 31, 2014. In November 2013 Central Hudson entered into a contract to purchase 200 MW of installed capacity from May 2014 through April 2017, with approximately US$34 million in purchase commitments remaining as at December 31, 2014.
FortisBC Electric
Power purchase obligations for FortisBC Electric are mainly comprised of a PPA with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term beginning in October 2013. This PPA was approved by the BCUC in May 2014 and was effective July 2014. The capacity and energy to be purchased under this agreement do not relate to a specific plant.
In November 2011 FortisBC Electric executed the Waneta Expansion Capacity Agreement ("WECA"). The WECA allows FortisBC Electric to purchase capacity over 40 years upon completion of the Waneta Expansion, which is expected in spring 2015. In May 2012 the WECA was accepted for filing as an energy supply contract by the BCUC. Amounts associated with the WECA have not been included in the Contractual Obligations table as they are to be paid by FortisBC Electric to a related party and such a related-party transaction would be eliminated upon consolidation with Fortis.
FortisBC Electric is also party to various agreements to purchase fixed-price capacity and energy purchases through 2017. The purchases under these agreements do not relate to specific plants, and/or the output being purchased does not constitute a significant portion of the output of a specific plant.
FortisOntario
Power purchase obligations for FortisOntario primarily include two long-term take-or-pay contracts between Cornwall Electric and Hydro-Québec Energy Marketing for the supply of energy and capacity. The first contract provides approximately 237 GWh of energy per year and up to 45 MW of capacity at any one time. The second contract, supplying the remainder of Cornwall Electric's energy requirements, provides 100 MW of capacity and energy and provides a minimum of 300 GWh of energy per contract year. Both contracts expire in December 2019.
(5) Maritime Electric has entitlement to approximately 4.55% of the output from New Brunswick Power's Point Lepreau nuclear generating station for the life of the unit. As part of its entitlement, Maritime Electric is required to pay its share of the capital and operating costs of the unit.
(6) Gas purchase obligations include various gas purchase contracts held by certain of the Corporation's subsidiaries, mainly the FortisBC Energy companies and Central Hudson. At the FortisBC Energy companies, the obligations include the gross cash payments associated with natural gas derivatives and are based on market prices as at December 31, 2014. At Central Hudson, the obligations are based on tariff rates, negotiated rates and market prices as at December 31, 2014.
(7) UNS Energy is party to renewable energy credit purchase agreements, totalling approximately US$126 million as at December 31, 2014, to purchase the environmental attributions from retail customers with solar installations. Payments for the renewable energy credit purchase agreements are paid in contractually agreed-upon intervals based on metered renewable energy production.
(8) UNS Energy has entered into a commitment to exercise its fixed-price purchase provision to purchase an undivided 50% leased interest in the Springerville Common Facilities if the lease is not renewed, for a purchase price of US$106 million, with one facility to be acquired in 2017 and the remaining two facilities to be acquired in 2021.
(9) Consolidated defined benefit pension funding contributions include current service, solvency and special funding amounts. The contributions are based on estimates provided under the latest completed actuarial valuations. As a result, actual pension funding contributions may be higher than these estimated amounts, pending completion of the next actuarial valuations for funding purposes. The dates of the most recent actuarial valuations of each of the Corporation's pension plans, as well as the requirements for the next actuarial valuations, are detailed in Note 28 to the Corporation's 2014 Audited Consolidated Financial Statements.
(10) Operating lease obligations include certain office, warehouse, natural gas T&D asset, rail car, land easement and rights-of-way, and vehicle and equipment leases.
(11) Payment is expected to be made in 2020 and relates to certain intangible assets and project design costs acquired from a company affiliated with CPC/CBT related to the construction of the Waneta Expansion. The amount disclosed is on a gross cash flow basis. The promissory note was recorded in long-term other liabilities at its discounted net present value of $53 million as at December 31, 2014.
(12) FortisAlberta and an Alberta transmission service provider have entered into an agreement to allow for joint attachments of distribution facilities to the transmission system, as well as service agreements to ensure operational efficiencies are maintained through coordinated operations. The expiry terms of the joint attachment agreement state that the agreement remains in effect until FortisAlberta no longer has attachments to the transmission system. Due to the unlimited term of this agreement, the calculation of future payments after 2019 includes payments to the end of 20 years, however, payments under this agreement may continue for an indefinite period of time.
(13) Other contractual obligations include various other commitments entered into by the Corporation and its subsidiaries, including Performance Share Unit and Deferred Share Unit Plan obligations and asset retirement obligations.

Other Contractual Obligations

Capital Expenditures: The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. The regulated utilities' capital expenditures are largely driven by the need to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet customer growth. The Corporation's consolidated capital expenditure program, including capital spending at its non-regulated operations, is forecast to be approximately $2.2 billion for 2015. Over the five years 2015 through 2019, the Corporation's consolidated capital expenditure program is expected to approach $9 billion, which has not been included in the Contractual Obligations table.

Other: CH Energy Group is party to an investment to develop, own and operate electric transmission projects in New York State. In December 2014 an application was filed with FERC for the recovery of the cost of and return on five high-voltage transmission projects totalling US$1.7 billion, of which CH Energy Group's maximum commitment is US$182 million.

In 2014 Caribbean Utilities renewed its primary and secondary fuel supply contracts and is committed to purchasing approximately 60% and 40%, respectively, of the Company's diesel fuel requirements under the contracts for the operation of its diesel-powered generating plant. The approximate combined quantity under the contracts for 2015 is 30 million imperial gallons.

Fortis Turks and Caicos has a renewable contract with a major supplier for all of its diesel fuel requirements associated with the generation of electricity. The approximate fuel requirements under this contract are 12 million imperial gallons per annum.

The Corporation's long-term regulatory liabilities of $1,363 million as at December 31, 2014 have been excluded from the Contractual Obligations table above, as the final timing of settlement of many of the liabilities is subject to further regulatory determination or the settlement periods are not currently known. The nature and amount of the long-term regulatory liabilities are detailed in Note 7 to the Corporation's 2014 Audited Consolidated Financial Statements.

CAPITAL STRUCTURE

The Corporation's principal businesses of regulated electric and gas distribution require ongoing access to capital to enable 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. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 45% equity, including preference shares, and 55% 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 each of the utility's customer rates.

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

Capital Structure
As at December 31 2014 2013
($ millions) (%) ($ millions) (%)
Total debt and capital lease and finance
obligations (net of cash) (1) 11,304 56.5 7,716 56.2
Preference shares 1,820 9.1 1,229 9.0
Common shareholders' equity 6,871 34.4 4,772 34.8
Total (2) 19,995 100.0 13,717 100.0
(1) Includes long-term debt and capital lease and finance obligations, including current portions, and short-term borrowings, net of cash
(2) Excludes amounts related to non-controlling interests

Excluding capital lease and finance obligations, the Corporation's capital structure as at December 31, 2014 was 55.0% debt, 9.4% preference shares and 35.6% common shareholders' equity (December 31, 2013 - 54.9% debt, 9.2% preference shares and 35.9% common shareholders' equity).

The Corporation's capital structure is comparable with December 31, 2013. The acquisition of UNS Energy significantly impacted the components of the capital structure and included the following: (i) the issuance of approximately 58.5 million common shares as a result of the conversion of substantially all of the $1.8 billion of Convertible Debentures issued to finance a portion of the acquisition; (ii) debt assumed upon acquisition; (iii) the issuance of First Preference Shares, Series M in September 2014 for net after-tax proceeds of $591 million to finance a portion of the acquisition; and (iv) borrowings under the Corporation's acquisition credit facility and committed credit facility to finance the remainder of the acquisition. The capital structure was also impacted by: (i) an increase in total debt, mainly in support of energy infrastructure investment and due to the impact of foreign exchange on the translation of US-dollar denominated debt; (ii) net earnings attributable to common equity shareholders for the year ended December 31, 2014, less dividends declared on common shares; (iii) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US-dollar denominated investments in subsidiaries, net of hedging activities and tax; and (iv) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.

CREDIT RATINGS

As at December 31, 2014, the Corporation's credit ratings were as follows:

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

The above-noted 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, and management's commitment to maintaining low levels of debt at the holding company level. In October 2014, following the completion of equity financing associated with the acquisition of UNS Energy, S&P confirmed the Corporation's credit rating and revised its outlook to Stable. Similarly, in December 2014 DBRS confirmed the Corporation's credit rating with a Stable outlook.

CAPITAL EXPENDITURE PROGRAM

Capital investment in infrastructure is required to ensure continued and enhanced performance, reliability and safety of the electricity and gas 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. Approximately $203 million in maintenance and repairs was expensed in 2014 compared to approximately $126 million in 2013.

Gross consolidated capital expenditures for 2014 were approximately $1.7 billion. A breakdown of gross consolidated capital expenditures by segment and asset category for 2014 is provided in the following table.

Gross Consolidated Capital Expenditures (1)
Year Ended December 31, 2014
($ millions)
Regulated Utilities Non-Regulated
FortisBC Total
UNS Central Energy Fortis FortisBC Eastern Electric Regulated Fortis Non-
Energy Hudson Companies Alberta Electric Canadian Caribbean Utilities Generation Utility (2) Total
Generation 303 - - - 7 13 43 366 102 - 468
Transmission 30 39 38 - 31 16 1 155 - - 155
Distribution 44 57 130 273 44 123 16 687 - - 687
Facilities, equipment, vehicles and other (3) 55 20 141 61 4 7 7 295 - 44 339
Information technology 12 10 23 14 6 7 4 76 - - 76
Total 444 126 332 348 92 166 71 1,579 102 44 1,725
(1) Relates to cash payments to acquire or construct utility capital assets, non-utility capital assets and intangible assets, as reflected on the consolidated statement of cash flows. Excludes the non-cash equity component of the AFUDC.
(2) Includes capital expenditures of approximately $6 million at FAES, which is reported in the Corporate and Other segment
(3) Includes capital expenditures associated with the Tilbury Expansion at the FortisBC Energy companies

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 those forecast. Gross consolidated capital expenditures of $1,725 million for 2014 were $295 million higher than $1,430 million forecast for 2014, as disclosed in the MD&A for the year ended December 31, 2013. The increase was driven by capital expenditures of $444 million at UNS Energy from the date of acquisition, which were not included in the original 2014 forecast. The increase was partially offset by lower-than-forecast capital spending at FortisAlberta, FortisBC Electric, the non-regulated Waneta Expansion and Fortis Properties. At FortisAlberta, required contributions toward transmission projects, as approved by the regulator, were lower than originally forecast. The decrease at FortisBC Electric was largely due to the timing of payments and the timing of receipt of the Company's PBR decision in 2014. Lower capital expenditures related to the Waneta Expansion for 2014 were primarily due to the timing of payments. Capital expenditures at Fortis Properties for 2014 were lower than forecast, mainly due to the Company's ongoing strategic review that was announced in September 2014.

Gross consolidated capital expenditures for 2015 are expected to be approximately $2.2 billion. A breakdown of forecast gross consolidated capital expenditures by segment and asset category for 2015 is provided in the following table.

Forecast Gross Consolidated Capital Expenditures (1)
Year Ending December 31, 2015
($ millions)
Regulated Utilities Non-Regulated
FortisBC Total
UNS Central Energy Fortis FortisBC Eastern Electric Regulated Fortis Non-
Energy Hudson Companies Alberta Electric Canadian Caribbean Utilities Generation Utility (2) Total
Generation 264 1 - - 3 7 90 365 78 - 443
Transmission 163 52 82 - 19 21 2 339 - - 339
Distribution 131 79 123 329 33 110 28 833 - - 833
Facilities, equipment, vehicles and other (3) 87 20 158 70 42 10 4 391 - 36 427
Information technology 39 13 22 18 6 11 1 110 - - 110
Total 684 165 385 417 103 159 125 2,038 78 36 2,152
(1) Relates to forecast cash payments to acquire or construct utility capital assets, non-utility capital assets and intangible assets, as would be reflected on the consolidated statement of cash flows. Excludes the non-cash equity component of AFUDC.
(2) Includes forecast capital expenditures of approximately $33 million at FAES, which is reported in the Corporate and Other segment
(3) Includes capital expenditures associated with the Tilbury Expansion at the FortisBC Energy companies

The percentage breakdown of 2014 actual and 2015 forecast gross consolidated capital expenditures among growth, sustaining and other is as follows.

Gross Consolidated Capital Expenditures
Year Ending December 31 Actual Forecast
(%) 2014 2015
Growth (1) 41 29
Sustaining (2) 35 46
Other (3) 24 25
Total 100 100
(1) Reflects UNS Energy's purchase of Unit 3 of the Gila River generating station in December 2014
(2) Capital expenditures required to ensure continued and enhanced performance, reliability and safety of generation and T&D assets
(3) Relates to facilities, equipment, vehicles, information technology systems and other assets, including AESO transmission-related capital expenditures at FortisAlberta and capital expenditures associated with the Tilbury Facility Expansion at the FortisBC Energy companies

Over the five-year period 2015 through 2019, gross consolidated capital expenditures are expected to approach $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 38% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 35% at Regulated Electric & Gas Utilities in the United States; 20% at Canadian Regulated Gas Utilities; 5% at Caribbean Regulated Electric Utilities; and the remaining 2% at non-regulated operations. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the five-year period, on average annually, the approximate breakdown of the total capital spending to be incurred is as follows: 28% to meet customer growth; 49% to ensure continued and enhanced performance, reliability and safety of generation and T&D assets, i.e., sustaining capital expenditures; and 23% for facilities, equipment, vehicles, information technology and other assets.

Forecast 2015 midyear rate base for the Corporation's regulated utilities is provided in the following table.

Forecast Midyear Rate Base
($ billions) 2015
UNS Energy (1) 3.8
Central Hudson (1) 1.3
FortisBC Energy Companies 3.7
FortisAlberta 2.7
FortisBC Electric 1.3
Eastern Canadian Electric Utilities 1.6
Regulated Electric Utilities - Caribbean (1) 0.8
Total 15.2
(1) Based on a forecast exchange rate of US$1.00=CDN$1.20

Significant capital projects for 2014 and 2015 are summarized in the table below.

Significant Capital Projects (1) Forecast Expected
($ millions) Pre- Actual Forecast Post- Year of
Company Nature of Project 2014 2014 2015 2015 Completion
UNS Energy (2) Gila River Unit 3 - 252 - - 2014
Interest in Springerville Unit 1 - 23 55 - 2015
Springerville Coal Handling Facilities Lease Buyout - 88 - 2015
Pinal Transmission Project - 9 92 - 2015
FortisBC Energy Companies Tilbury LNG Facility Expansion 5 97 170 128 2016
FortisAlberta Pole-Management Program 132 27 41 114 Post-2019
Caribbean Utilities (2) Generation Expansion - 12 58 30 2016
Waneta Partnership Waneta Expansion (3) 579 100 76 72 2015
(1) Relates to utility capital asset, non-utility capital asset and intangible asset expenditures combined with both the capitalized interest and equity components of AFUDC, where applicable
(2) Forecast capital expenditures are based on a forecast exchange rate of US$1.00=CDN$1.20.
(3) Includes the $72 million payment expected to be made in 2020 and excludes forecast capitalized interest of the minority partners, CPC/CBT, in the Waneta Partnership

In December 2014 UNS Energy purchased Unit 3 of the Gila River generating station, which is a gas-fired combined-cycle unit with a capacity of 550 MW, for approximately $252 million (US$219 million). The purchase of Gila River Unit 3 is consistent with the Company's long-term energy resource diversification strategy.

UNS Energy leases Unit 1 of the Springerville Generating Station ("Springerville Unit 1") and a portion of the related coal handling facilities located at Springerville, Arizona. In 2006 the Company purchased a 14.1% undivided ownership interest in Springerville Unit 1 and agreed to purchase additional undivided ownership interests totalling 35.4%. In December 2014 and January 2015, UNS Energy closed the purchases of the additional ownership interests in Springerville Unit 1 for US$20 million and US$46 million, respectively, after which its ownership interests total 49.5%. Additionally, in 2015 UNS Energy expects to purchase expiring lease interests in the Springerville Coal Handling Facilities for US$73 million, net of expected reimbursements from third parties.

The Pinal Transmission Project at UNS Energy is the construction of a transmission line in Pinal County that will increase the Company's import capacity from Gila River Unit 3 and the Palo Verde trading hub. Construction of the transmission line is expected to be complete by the end of 2015, at a total projected cost of US$85 million.

FEI has begun the expansion of the Tilbury LNG facility. The expansion will include a second LNG tank and a new liquefier, both to be in service by the end of 2016. The expansion will increase LNG production and storage capabilities. The Government of British Columbia imposed an upper limit of $400 million for capital costs associated with the expansion, with approximately $170 million expected to be spent in 2015.

During 2014 FortisAlberta continued with the replacement of vintage poles under its Pole-Management Program to replace 110,000 vintage poles that were not chemically treated to prevent risk of failure due to age. The total capital cost of the program through 2019 is expected to be approximately $314 million. Approximately $27 million was spent on this program in 2014, for a total of $159 million spent to date.

Caribbean Utilities was the successful bidder for new generation capacity and will develop and operate a new 39.7 MW diesel-power plant, including two 18.5 MW diesel-generating units and a 2.7 MW waste heat recovery steam turbine. The project cost is estimated at US$85 million and the plant is expected to be commissioned no later than June 2016.

Construction of the $900 million Waneta Expansion is ongoing, with an additional $100 million invested in 2014. Approximately $679 million in total has been spent on the Waneta Expansion since construction began in late 2010, with approximately $76 million expected to be spent in 2015. Fortis owns a 51% interest in the Waneta Partnership and will operate and maintain the non-regulated investment when the facility comes into service, which is expected in spring 2015.

Key construction activities at the Waneta Expansion in 2014 were focused on civil construction and equipment installation, assembly, testing and pre-commissioning. Civil construction was substantially completed, which included the intake structure, two power tunnels and transitions and excavation of the tailrace channel. Also substantially completed were the powerhouse mechanical and electrical auxiliary systems. Removal of the tailrace and intake plugs continued through the end of 2014 and is forecast to be substantially complete in early 2015. Assembly continued with the turbine and generator components with the first unit successfully completing the mechanical run test in December. The second unit commenced mechanical run testing in January 2015. Forecast for early 2015 is the completion of testing and commissioning, marketable power tests followed by substantial completion in the spring of 2015.

The capital cost of the Waneta Expansion, as reported in the Significant Capital Projects table above, includes capitalized interest by Fortis during construction, as well as other eligible capitalized expenses, and a $72 million payment expected to be made in 2020 related to accrued development costs previously incurred by CPC/CBT. The table excludes approximately $50 million of forecast capitalized interest of the minority partners in the Waneta Partnership.

The Waneta Expansion is 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. The surplus capacity, equal to approximately 234 MW on an average annual basis, will be sold to FortisBC Electric under a long-term capacity purchase agreement.

CASH FLOW REQUIREMENTS

At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flows available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, equity injections from Fortis and long-term debt offerings.

The Corporation's ability to service its debt obligations and pay dividends on its common shares and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries may be subject to restrictions that may limit their ability to distribute cash to Fortis.

Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends.

The subsidiaries expect to be able to source the cash required to fund their 2015 capital expenditure programs.

Management expects consolidated long-term debt maturities and repayments, excluding credit facility borrowings, to be $268 million in 2015 and to average approximately $240 million annually over the next five years. The combination of available credit facilities and relatively low annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets. For a discussion of capital resources and liquidity risk, refer to the "Business Risk Management - Capital Resources and Liquidity Risk" section of this MD&A.

Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2014 and are expected to remain compliant in 2015.

CREDIT FACILITIES

As at December 31, 2014, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.9 billion, of which approximately $2.2 billion was unused, including $509 million unused under the Corporation's $1 billion committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, with no one bank holding more than 20% of these facilities. Approximately $3.7 billion of the total credit facilities are committed facilities with maturities ranging from 2015 through 2019.

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

Credit Facilities

($ millions)

Regulated
Utilities

Non-
Regulated

Corporate
and Other
Total
as at
December
31,
2014
Total
as at
December
31, 2013
Total credit facilities 2,248 12 1,594 3,854 2,695
Credit facilities utilized:
Short-term borrowings (325 ) (5 ) - (330 ) (160 )
Long-term debt (including current portion) (258 ) - (838 ) (1,096 ) (313 )
Letters of credit outstanding (161 ) - (31 ) (192 ) (66 )
Credit facilities unused 1,504 7 725 2,236 2,156

As at December 31, 2014 and 2013, certain borrowings under the Corporation's and subsidiaries' credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.

Regulated Utilities

The UNS Utilities have a total of US$370 million ($429 million) in unsecured committed revolving credit facilities, of which US$300 million ($348 million) matures in November 2016 and the remaining US$70 million ($81 million) matures in November 2015. The UNS Utilities also have a US$130 million ($151 million) term loan commitment and a US$82 million ($95 million) letter of credit facility, maturing in November 2015 and 2016, respectively.

Central Hudson has a US$150 million ($174 million) unsecured committed revolving credit facility, maturing in October 2016, that is utilized to finance capital expenditures and for general corporate purposes.

FEI has a $500 million unsecured committed revolving credit facility, maturing in August 2016, and a $200 million unsecured committed revolving credit facility, maturing in December 2015. The facilities are utilized to finance working capital requirements and capital expenditures and for general corporate purposes.

FortisAlberta has a $250 million unsecured committed revolving credit facility, maturing in August 2019, that is utilized to finance capital expenditures and for general corporate purposes.

FortisBC Electric has a $150 million unsecured committed revolving credit facility, of which $50 million matures in April 2015 and the remaining $100 million matures in May 2017. This facility is utilized to finance capital expenditures and for general corporate purposes. FortisBC Electric also has a $10 million unsecured demand overdraft facility.

Newfoundland Power has a $100 million committed revolving credit facility, which matures in August 2019, and a $20 million demand credit facility. Maritime Electric has a $50 million unsecured committed revolving credit facility, maturing in February 2019, and a $5 million unsecured demand credit facility. FortisOntario has a $30 million unsecured committed revolving credit facility, maturing in June 2015.

Caribbean Utilities has unsecured credit facilities totalling approximately US$47 million ($54 million). Fortis Turks and Caicos has short-term unsecured demand credit facilities of US$26 million ($30 million), maturing in September 2015.

Non-Regulated - Non-Utility

Fortis Properties has a $12 million secured revolving demand credit facility that can be utilized for general corporate purposes.

Corporate and Other

Fortis has a $1 billion unsecured committed revolving credit facility, maturing in July 2018, that is available for general corporate purposes; a $273 million medium-term bridge facility secured to initially finance a portion of the acquisition of UNS Energy, maturing in August 2016; and a $30 million letter of credit facility, maturing in January 2016.

UNS Energy Corporation has a US$125 million ($145 million) unsecured committed revolving credit facility, maturing in November 2016.

CH Energy Group has a US$100 million ($116 million) unsecured committed revolving credit facility, maturing in October 2015, that can be utilized for general corporate purposes.

FHI has a $30 million unsecured committed revolving credit facility, maturing in April 2015, that is available for general corporate purposes.

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $192 million as at December 31, 2014 (December 31, 2013 - $66 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. The increase in letters of credit outstanding is primarily a result of the acquisition of UNS Energy and is largely associated with certain of the Company's long-term debt obligations.

BUSINESS RISK MANAGEMENT

The following is a summary of the Corporation's significant business risks.

Regulatory Risk: The Corporation's key business risk is regulation. Regulated utility assets comprised approximately 93% of total assets of Fortis as at December 31, 2014 (December 31, 2013 - 90%). Approximately 95% of the Corporation's operating revenue1 was derived from regulated utility operations in 2014 (2013 - 93%), while approximately 91% of the Corporation's operating earnings1 were derived from regulated utility operations in 2014 (2013 - 87%). The Corporation operates nine utilities in different jurisdictions in Canada, the United States and the Caribbean, with no more than one-third of total assets located in any one regulatory jurisdiction.

(1) Operating revenue and operating earnings are non-US GAAP measures and refer to total revenue, excluding Corporate and Other segment revenue and inter-segment eliminations, and net earnings attributable to common equity shareholders, excluding Corporate and Other segment expenses, respectively. Operating revenue and operating earnings are referred to by users of the consolidated financial statements in evaluating the performance of the Corporation's operating subsidiaries.

Each of the Corporation's regulated utilities is subject to normal regulation that can affect future revenue and earnings. As a result, the utilities are subject to uncertainties faced by regulated entities, including approval by the respective regulatory authorities of electricity and gas rates that permit a reasonable opportunity to recover, on a timely basis, the estimated COS, including a fair rate of return on rate base and, in the case of utilities in the Caribbean, the continuation of licences. Generally, the ability of a utility to recover the actual COS and earn the approved ROE and/or ROA depends on achieving the forecasts established in the rate-setting processes. When PBR mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudent cost of service and earn its allowed ROE.

Electricity and gas infrastructure investments require the approval of the regulatory authorities, either through the approval of capital expenditure plans or revenue requirements for the purpose of setting electricity and gas rates, which include the impact of capital expenditures on rate base and/or COS. There is no assurance that capital projects perceived as required or completed by the Corporation's regulated utilities will be approved. Capital cost overruns may not be recoverable in customer rates.

Regulators approve the allowed ROEs and deemed capital structures. Fair regulatory treatment that allows a utility to earn a fair risk-adjusted rate of return, comparable to that available on alternative investments of similar risk, is essential for maintaining service quality, as well as ongoing capital attraction and growth. Rate applications establishing revenue requirements may be subject to negotiated settlement procedures. Failing a negotiated settlement, rate applications may be pursued through a litigated public hearing process. There can be no assurance that resulting rate orders issued by the regulators will permit the regulated utilities to recover all costs actually incurred and to earn the expected or fair rates of return on an appropriate capitalization.

A failure to obtain acceptable rate orders, appropriate ROEs or capital structures as applied for may adversely affect the business carried on by the regulated utilities, the undertaking or timing of capital expenditures, ratings assigned by credit rating agencies, the issuance of long-term debt and other matters, which may, in turn, have a material adverse effect on the results of operations and financial position of the Corporation's regulated utilities. In addition, there is no assurance that the regulated utilities will receive regulatory decisions in a timely manner and, therefore, costs may be incurred prior to having an approved revenue requirement.

Significant regulatory uncertainty remains at FortisAlberta associated with the capital tracker mechanism under the PBR formula, which became effective January 1, 2013. The final decision on FortisAlberta's combined 2013, 2014 and 2015 Capital Tracker Application is expected in the first quarter of 2015. In December 2014 the regulator approved, on an interim basis, customer distribution rates for 2015 based on 90% of the applied for capital tracker amounts, as compared to 60% approved on an interim basis for 2013 and 2014. Any adjustment to interim capital tracker amounts will result in an adjustment to revenue. During its PBR term, FortisAlberta is exposed to risks related to the PBR formula, specifically that: (i) the Company will experience inflationary increases in excess of the inflationary factor set by the AUC; (ii) the Company will be unable to achieve the productivity improvements expected over the PBR term; (iii) the costs related to FortisAlberta's capital expenditures will be in excess of those provided for in the base formula and excess capital expenditures will not qualify, or be approved, as a capital tracker where necessary; and (iv) material unforeseen costs will be incurred that will not qualify or be approved. FortisAlberta's final allowed ROE and capital structure for 2013 through 2015 are also to be determined, subject to the outcome of the GCOC Proceeding, which is also expected in the first quarter of 2015.

As an owner of an electricity distribution network under the Electric Utilities Act (Alberta), FortisAlberta is required to act, or to authorize a substitute party to act, as a provider of electricity services, including the sale of electricity, to eligible customers under a regulated rate and to appoint a retailer as a default supplier to provide electricity services to customers otherwise unable to obtain electricity services. In order to remain solely a distribution utility, FortisAlberta appointed EPCOR Energy Services (Alberta) Inc. ("EPCOR") as its regulated-rate provider. As a result of this appointment, EPCOR assumed all of FortisAlberta's rights and obligations in respect of these services. In the unlikely event that EPCOR is unable or unwilling to act as a regulated-rate provider or default supplier, and no other party is willing to act in this capacity, FortisAlberta would be required to act as a provider of electricity services to eligible customers under a regulated rate or to provide electricity services to customers otherwise unable to obtain electricity services. If FortisAlberta could not secure outsourcing for these functions, it would need to administer these retail responsibilities by adding necessary staff, facilities and/or equipment.

The Corporation's regulated utilities in British Columbia are also subject to PBR mechanisms. In September 2014 the BCUC issued it decisions on FEI's and FortisBC Electric's Multi-Year PBR plans for 2014 through 2019. Rates during this term will be determined through a review process that occurs on an annual basis. There can be no assurance that the rate orders issued will permit FEI and FortisBC Electric to recover all costs actually incurred and to earn the expected rate of return.

For additional information on the nature of regulation and various regulatory matters pertaining to the Corporation's utilities, refer to the "Regulatory Highlights" section of this MD&A.

Interest Rate Risk: Generally, allowed ROEs for regulated utilities in North America are exposed to changes in long-term interest rates. Such rates affect allowed ROEs directly when they are applied in formulaic ROE AAMs or indirectly through a regulatory process of what constitutes an appropriate rate of return on investment, which may consider the general level of interest rates as a factor for setting allowed ROEs. Uncertainty exists regarding the duration of the current environment of low interest rates and the effect it may have on allowed ROEs of the Corporation's regulated utilities. If interest rates continue to remain at historically low levels, allowed ROEs could decrease. The continuation of a low interest rate environment could adversely affect the Corporation's ability to earn a reasonable ROE, which could have a negative effect on the financial condition and results of operations of the Corporation's regulated utilities. Also, if interest rates begin to climb, regulatory lag may cause a delay in any resulting increase in cost of capital and the regulatory allowed ROEs.

The Corporation and its subsidiaries may also be exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and refinancing of long-term debt. Central Hudson, the FortisBC Energy companies and FortisBC Electric, however, have regulatory approval to defer any increase or decrease in interest expense, resulting from fluctuations in interest rates associated with variable-rate credit facilities for recovery from, or refund to, customers in future rates. There can be no assurance that such deferral mechanisms will exist in the future, as they are dependent on future regulatory decisions. UNS Energy and Central Hudson use interest rate swaps and interest rate caps on variable-rate long-term debt to reduce risk associated with interest rates, as permitted by the regulators. At the Corporation's other regulated utilities, if the timing of issuance of, and the interest rates on, long-term debt are different from those forecast and approved in customer rates, the additional or lower interest costs incurred on the new long-term debt are not recovered from, or refunded to, customers in rates during the period that was covered by the approved customer rates. An inability to flow through interest costs to customers could have a material adverse effect on the results of operations and financial position of the utilities.

Excluding borrowings under long-term committed credit facilities, approximately 87% of the Corporation's consolidated long-term debt as at December 31, 2014 had maturities beyond five years. With a significant portion of the Corporation's consolidated debt having long-term maturities, interest rate risk on debt refinancing has been reduced for the near and medium terms.

The following table outlines the nature of the Corporation's consolidated debt as at December 31, 2014.

Total Debt
As at December 31, 2014 ($ millions) (%)
Short-term borrowings 330 3.0
Utilized variable-rate credit facilities classified as long term 1,096 10.1
Variable-rate long-term debt (including current portion) 333 3.1
Fixed-rate long-term debt (including current portion) 9,072 83.8
Total 10,831 100.0

In 2014 the Corporation and certain of its regulated subsidiaries issued more than $1 billion in long-term debt, the majority of which was at fixed interest rates. Fixed-rate debt was issued at interest rates ranging from 2.45% to 5.03% with terms ranging from 5 to 32 years. The terms negotiated on new long-term debt demonstrate the ability of the Corporation and its utilities to raise long-term capital at attractive rates. Further information on the Corporation's consolidated long-term debt issuances is provided in the "Liquidity and Capital Resources" section of this MD&A.

A change in the level of interest rates could materially affect the measurement and disclosure of the fair value of long-term debt. The fair value of the Corporation's consolidated long-term debt, as at December 31, 2014, is provided in the "Financial Instruments" section of this MD&A.

Operating and Maintenance Risks: Storms, natural disasters, wars, terrorist acts, failure of critical equipment and other catastrophic events occurring both within and outside the service territories of the Corporation's utilities could result in service disruptions, leading to lower earnings and/or cash flows if the situation is not resolved in a timely manner or the financial impacts of restoration are not alleviated through insurance policies or regulated rate recovery. UNS Energy, Central Hudson and the FortisBC Energy companies are exposed to various operational risks, such as: pipeline leaks, accidental damage to mains and service lines, corrosion in pipes, pipeline or equipment failure, other issues that can lead to outages and/or leaks, and any other accidents involving natural gas that could result in significant operational disruptions and/or environmental liability.

The operation of UNS Energy's electric generating stations involves certain risks, including equipment breakdown or failure, interruption of fuel supply and lower-than-expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failure or other complications, occur from time to time and are an inherent risk of the generation business. There can be no assurance that the generation facilities of UNS Energy will continue to operate in accordance with expectations.

The operation of electricity T&D assets is also subject to risks, including the potential to cause fires, mainly as a result of equipment failure, falling trees and lightning strikes to lines or equipment. In addition, a significant portion of the utilities' infrastructure is located in remote areas, which may make access to perform maintenance and repairs difficult if such assets become damaged. The FortisBC utilities operate in remote and mountainous terrain with a risk of loss or damage from forest fires, floods, washouts, landslides, avalanches and other acts of nature. UNS Energy, the FortisBC Energy companies, FortisBC Electric and the Corporation's operations in the Caribbean region are subject to risk of loss from earthquakes.

The Corporation and its subsidiaries have limited insurance that provides coverage for business interruption, liability and property damage. In the event of a large uninsured loss caused by severe weather conditions, natural disasters and certain other events beyond the control of the utility, an application would be made to the respective regulatory authority for the recovery of these costs through customer rates to offset any loss. However, there can be no assurance that the regulatory authorities would approve any such application in whole or in part. Refer to the "Business Risk Management - Insurance Coverage Risk" section of this MD&A for a further discussion on insurance.

The Corporation's electricity and gas systems require ongoing maintenance, improvement and replacement. The utilities could experience service disruptions and increased costs if they are unable to maintain their asset base. The inability to recover, through approved customer rates, the expenditures the utilities believe are necessary to maintain, improve, replace and remove assets; the failure by the utilities to properly implement or complete approved capital expenditure programs; or the occurrence of significant unforeseen equipment failures, despite maintenance programs, could have a material adverse effect on the financial position and results of operations of the Corporation's utilities.

Generally, the Corporation's utilities have designed their electricity and natural gas systems to service customers under various contingencies in accordance with good utility practice. The utilities are responsible for operating and maintaining their assets in a safe manner, including the development and application of appropriate standards, processes and/or procedures to ensure the safety of employees and contractors, as well as the general public. Failure to do so may disrupt the ability of the utilities to safely distribute gas and electricity, which could have a material adverse effect on the operations of the utilities.

The Corporation's utilities continually develop capital expenditure programs and assess current and future operating and maintenance expenses that will be incurred in the ongoing operation of their gas and electricity systems. Management's analysis is based on assumptions as to COS and equipment, regulatory requirements, revenue requirement approvals and other matters, which involve some degree of uncertainty. If actual costs exceed regulator-approved capital expenditures, it is uncertain whether any additional costs will receive regulatory approval for recovery in future customer rates. It is generally expected, however, that prudently incurred costs can be recovered in customer rates. The inability to recover additional costs, however, could have a material adverse effect on the utilities' financial position and results of operations. Refer also to the "Business Risk Management - Regulatory Risk" section of this MD&A.

Economic Conditions: Typical of utilities, economic conditions, such as changes in employment levels, personal disposable income, energy prices and housing starts, in the Corporation's service territories influence energy sales. Declines in energy sales could adversely impact the respective utilities' results of operations, net earnings and cash flows.

The business of UNS Energy is concentrated in the State of Arizona. In recent years economic conditions in Arizona have contributed significantly to a reduction in retail customer growth and lower energy usage by the Company's residential, commercial and industrial customers. While it is expected that economic conditions in Arizona will improve in the future, if they do not or if they should worsen, retail customer growth rates may stagnate or decline and customers' energy usage may further decline.

The FortisBC Energy companies are affected by the trend in housing starts from single-family dwellings to multi-family dwellings, for which natural gas has a lower penetration rate. The growth in new multi-family housing starts continues to significantly outpace that of new single-family homes, which may temper growth in gas distribution volumes.

Generally, higher energy prices can result in reduced consumption by customers. Natural gas and crude oil exploration and production activities in certain of the Corporation's service territories are closely correlated with natural gas and crude oil prices. The level of these activities, which tend to increase with higher energy prices, can influence energy demand, affecting local energy sales in some of the Corporation's service territories.

Alberta's economy is impacted by a number of factors, including the level of oil and gas activity in the province, which is influenced by the market prices of oil and gas. A general and extended decline in economic conditions in Alberta or in other jurisdictions where the Corporation's utilities operate would be expected to have the effect of reducing demand for electricity over time. The regulated nature of utility operations, including various mitigating measures approved by certain regulators, helps reduce the impact that lower energy demand associated with poor economic conditions may have on the utilities' earnings. Significantly reduced electricity demand in the Corporation's service areas could materially reduce capital spending forecasts, and specifically capital spending related to new customer growth. A reduction in capital spending would, in turn, affect the Corporation's rate base and earnings growth. A severe and prolonged downturn in economic conditions could have a material adverse effect on the Corporation's results of operations, net earnings and cash flows despite regulatory measures, where applicable, available to compensate for reduced demand. In addition to the impact of reduced energy demand, an extended decline in economic conditions could also impair the ability of customers to pay for the gas and electricity they consume, thereby affecting the aging and collection of the utilities' trade receivables.

The Corporation's service territory in the Caribbean region continues to be impacted by challenging economic conditions. Assets of Caribbean Regulated Electric Utilities comprise approximately 4% of the Corporation's total assets as at December 31, 2014. Activity in the tourism, real estate and construction sectors is closely tied to economic conditions in the region and changes in such activity affect customer electricity demand.

Capital Resources and Liquidity Risk: The Corporation's financial position could be adversely affected if it and/or its larger subsidiaries fail to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the results of operations and financial position of the Corporation and its subsidiaries, the regulatory environment in which the utilities operate and the nature and outcome of regulatory decisions regarding capital structure and allowed ROEs, conditions in the capital and bank credit markets, ratings assigned by credit rating agencies, and general economic conditions. Funds generated from operations after payment of expected expenses, including interest payments on any outstanding debt, may not be sufficient to fund the repayment of all outstanding liabilities when due and anticipated capital expenditures. There can be no assurance that sufficient capital will continue to be available on acceptable terms to fund capital expenditures and repay existing debt.

Consolidated long-term debt maturities in 2015 are expected to total $268 million, excluding credit facility borrowings. The ability to meet long-term debt repayments when due will be dependent on the Corporation and its subsidiaries obtaining sufficient and cost-effective financing. The Corporation and its utilities have been successful at raising long-term capital at reasonable rates. Activity in the global capital markets may impact the cost and timing of issuance of long-term capital by the Corporation and its subsidiaries. While the future cost of raising capital could increase, the Corporation and its subsidiaries expect to continue to have reasonable access to capital in the near to medium terms.

The cost of renewed and extended credit facilities could increase going forward. Due to their regulated nature, any forecast changes in the cost of borrowing at the utilities are eligible to be reflected in customer rates.

Generally, the Corporation and its currently rated regulated utilities are subject to financial risk associated with changes in the credit ratings assigned to them by credit rating agencies. Credit ratings affect the level of credit risk spreads on new long-term debt and credit facilities. A change in the credit ratings could potentially affect access to various sources of capital and increase or decrease finance charges of the Corporation and its utilities. Fortis and its regulated utilities do not anticipate any material adverse rating actions by the credit rating agencies in the near term.

The Corporation's credit ratings were affirmed by S&P in October 2014 and DBRS in December 2014, following the conversion of substantially all of the Convertible Debentures into common shares, and the outlooks were revised to Stable. In 2014 the following changes were made to the debt credit ratings of the Corporation's utilities: (i) Moody's Investor Service ("Moody's") upgraded Central Hudson's credit rating to 'A2' from 'A3' with a Stable outlook in January 2014; (ii) DBRS confirmed FortisAlberta's credit rating at 'A(low)' and changed the trend to Positive from Stable in February 2014; (iii) S&P confirmed Maritime Electric's and Caribbean Utilities' credit ratings at 'A' and 'A-', respectively, both with a Negative outlook in May 2014; (iv) in June 2014 Moody's affirmed the long-term credit ratings of FEI, FEVI and FortisBC Electric and changed the ratings outlook to Stable from Negative; (v) Fitch Ratings confirmed Central Hudson's credit rating at 'A' and revised the outlook to Negative from Stable in July 2014; (vi) in August 2014 Moody's affirmed the credit ratings of UNS Energy at 'Baa2' and TEP, UNS Electric and UNS Gas at 'Baa1' and changed the ratings outlook to Positive; and (vii) in October 2014, following the conversion of substantially all of Convertible Debentures into common shares, S&P revised its outlook on FortisAlberta, Maritime Electric and Caribbean Utilities to Stable and upgraded TEP's credit rating to 'BBB+' from 'BBB'. In addition, in July 2014 Turks and Caicos received its first sovereign credit rating of 'BBB+' from S&P and in September 2014 FortisTCI Limited ("FortisTCI") received its first credit rating of 'BBB' from S&P, with a Stable outlook.

In January 2015 DBRS confirmed FEI's and FHI's credit ratings at 'A' and 'BBB', respectively, with Stable outlook, following the amalgamation of FEI, FEVI and FEWI.

Additional information on the Corporation's consolidated credit facilities, contractual obligations, including long-term debt maturities and repayments, and consolidated cash flow requirements is provided in the "Liquidity and Capital Resources" section of this MD&A.

Expropriation of Shares in Belize Electricity: On June 20, 2011, the GOB enacted legislation leading to the expropriation of the Corporation's investment in Belize Electricity. Consequent to the deprivation of control over the operations of the utility, the Corporation discontinued the consolidation method of accounting for Belize Electricity, as of June 20, 2011, and classified the book value, including foreign exchange impacts, of the expropriated investment as a long-term other asset on the consolidated balance sheet.

In October 2011 Fortis commenced an action in the Belize Supreme Court with respect to challenging the constitutionality of the expropriation of the Corporation's investment in Belize Electricity. In July 2012 the Belize Supreme Court dismissed the Corporation's claim of October 2011. Also in July 2012, Fortis filed its appeal of the above-noted trial judgment in the Belize Court of Appeal. The appeal was heard in October 2012 and a decision was rendered by the Belize Court of Appeal in May 2014. The two Belizean judges found in favour of the GOB; however, the third judge delivered a strong dissenting opinion concluding that the expropriation was contrary to the Belize Constitution. An appeal of the decision to the CCJ, the final court for appeals arising in Belize, was filed in June 2014 and Fortis filed its written submission for appeal in October 2014. The case was brought before the CCJ for hearing in December 2014 and January 2015 and it is not known at this time when a judgment will be received.

Fortis believes it has a strong, well-positioned case supporting the unconstitutionality of the expropriation. There exists, however, a possibility that the outcome of the litigation may be unfavourable to the Corporation and the amount of compensation otherwise to be paid to Fortis under the legislation expropriating Belize Electricity could be lower than the book value of the Corporation's expropriated investment in Belize Electricity. If the expropriation is held to be unconstitutional, it is not determinable at this time as to the nature of the relief that would be awarded to Fortis; for example: (i) ordering return of the shares to Fortis and/or award of damages; or (ii) ordering compensation to be paid to Fortis for the unconstitutional expropriation of the shares and/or award of damages. Based on presently available information, the $116 million long-term other asset is not deemed impaired as at December 31, 2014. Fortis will continue to assess for impairment each reporting period based on evaluating the outcomes of court proceedings and/or compensation settlement negotiations.

Fortis continues to control and consolidate the financial statements of BECOL. While the Prime Minister of Belize has stated that the GOB has neither the intention nor the resources to expropriate BECOL, risk remains that this investment could be expropriated in the future.

Political Risk: The regulatory framework under which utilities operate is impacted by significant shifts in government policy and/or changes in governments, which create uncertainty about public policy priorities and directions, particularly around energy and environmental issues. For details related to environmental issues, refer to the "Business Risk Management - Environmental Risks" section of this MD&A.

Information Technology and Cyber-Security Risks: As operators of critical energy infrastructure, the Corporation's utilities may face a heightened risk of cyber attacks. Information technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes. The ability of the Corporation's utilities to operate effectively is dependent upon developing, managing and maintaining complex information systems and infrastructure that support the operation of generation and T&D facilities, including the communication infrastructure and supporting systems necessary to provide important safety information to mobile devices for field staff; provide customers with billing, consumption and load settlement information, where applicable; and support the financial and general operating aspects of the business. While the utilities have various measures in place to protect their information systems against cyber-security incidents, there is no assurance that such incidents will not occur.

Cyber-security threats are continuously changing and require ongoing monitoring and detection capabilities. Unauthorized access to corporate and information technology systems could result in service disruptions and system failures, which could have a material adverse effect on the utilities, such as the inability to provide energy to customers. In addition, in the normal course of operations, the Corporation's utilities and non-regulated subsidiaries require access to confidential customer data, including personal and credit information, which could be exposed in the event of a cyber-security incident.

The Corporation's subsidiaries have security measures and controls in place to protect corporate and information technology systems, and safeguard the confidentiality of customer information. Despite the existence of these security measures and controls, a cyber-security incident could result in service disruptions, property damage, corruption or unauthorized access to critical data or confidential customer information, lower earnings and/or cash flows, fines and other penalties, reputational damage and increased regulation and litigation, all of which could impact the Corporation's results of operations if the situation is not resolved in a timely manner, or if the financial impacts are not alleviated through insurance policies or, in the case of regulated utilities, through regulatory recovery.

Capital Project Budget Overrun, Completion and Financing Risk in the Corporation's Non-Regulated Business: In its non-regulated business, Fortis generally bears the risk of budget overruns on capital projects, including increased costs associated with higher financing expense, schedule delays and lower-than-expected performance. The risk of cost overruns is mitigated by contractual approach, regular and proactive monitoring by employees with appropriate expertise and regular review by senior management. Cost overruns and delays in project completion may also occur when unforeseen circumstances arise. The construction of the non-regulated Waneta Expansion remains on time and within budget with completion expected in spring 2015.

Weather and Seasonality Risk: The physical assets of the Corporation and its subsidiaries could be exposed to the effects of severe weather conditions and other acts of nature. Although the physical assets have been constructed and are operated and maintained to withstand severe weather, there is no assurance that they will successfully do so in all circumstances. Regulatory deferral mechanisms are in place at certain of the Corporation's regulated utilities, including Central Hudson, the FortisBC Energy companies, FortisBC Electric and Newfoundland Power, to minimize the volatility in earnings that would otherwise be caused by variations in weather conditions. The absence of the above-noted regulatory deferral mechanisms could have a material adverse effect on the results of operations and financial position of the utilities.

At the FortisBC Energy companies and the gas operations of UNS Energy and Central Hudson, weather has a significant impact on gas distribution volumes as a major portion of the gas distributed is ultimately used for space heating for residential customers. Because of gas consumption patterns, the gas utilities normally generate quarterly earnings that vary by season and may not be an indicator of annual earnings. The earnings associated with regulated gas utilities are highest in the first and fourth quarters.

Fluctuations in the amount of electricity used by customers can vary significantly in response to seasonal changes in weather. In Canada, Arizona and New York State, cool summers may reduce air conditioning demand, while less severe winters may reduce electric heating load. In the Caribbean, the impact of seasonal changes in weather on air conditioning demand is less pronounced due to the less variable seasonal changes that exist in the region; however, higher- or lower-than-normal temperatures can have a significant impact on air conditioning demand. Significant fluctuations in weather-related demand for electricity could materially impact the operations, financial condition and results of operations of the electric utilities.

Extreme climatic factors could potentially cause government authorities to adjust water flows on the Kootenay River, where FortisBC Electric's dams and related facilities are located, in order to protect the environment. This adjustment could affect the amount of water available for generation at FortisBC Electric's plants or at plants operated by parties contracted to supply energy to FortisBC Electric. Prolonged adverse weather conditions could lead to a significant and sustained loss of precipitation over the headwaters of the Kootenay River system, which could reduce the Corporation's entitlement to capacity and energy under the Canal Plant Agreement.

Natural gas and coal-fired plants require continuous water flow for their operation. Shifts in weather or climate patterns, seasonal precipitation, the timing and rate of melting, run off, and other factors beyond the control of the Corporation, may reduce the water flow to UNS Energy's generation facilities. Any material reduction in the water flow to UNS Energy's generation facilities would limit the ability of the Company to produce and market electricity from those respective facilities and could have a material adverse effect on the results of operations and financial position of the Corporation. Any change in regulations or the level of regulation respecting the use, treatment and discharge of water, or respecting the licensing of water rights in the jurisdictions where UNS Energy operates could result in a material adverse effect on the results of operations and financial position of the Company.

Despite preparations for severe weather, hurricanes and other natural disasters will always remain a risk to utilities. Climate change, however, may have the effect of increasing the severity and frequency of weather-related natural disasters that could affect the Corporation's service territories.

The assets and earnings of Caribbean Utilities, Fortis Turks and Caicos and, to a lesser extent, Central Hudson, Newfoundland Power and Maritime Electric, are subject to hurricane risk. Certain of the Corporation's utilities may also be subject to severe weather events, including ice, wind and snow storms. Weather risks are managed through insurance on generation assets, business-interruption insurance and self-insurance on T&D assets. Under its T&D licence, Caribbean Utilities may apply for a special additional customer rate in the event of a disaster such as a hurricane. Fortis Turks and Caicos does not have a specific hurricane cost-recovery mechanism; however, the Company may apply for an increase in customer rates in the following year if the actual ROA is lower than the allowed ROA due to additional costs resulting from a hurricane or other significant weather event. Central Hudson is authorized to request, and the PSC has typically approved, deferral account treatment for incremental storm restoration costs. To qualify for deferral, storm costs must meet certain criteria as stipulated by the PSC. In most cases, the Corporation's other regulated utilities can apply to their respective regulators for relief from major uncontrollable expenses, including those related to significant weather-related events.

Earnings from non-regulated generation assets are sensitive to rainfall levels. The Waneta Expansion is included in the Canal Plant Agreement and will receive fixed energy and capacity entitlements based upon long-term average water flows, thereby significantly reducing the hydrologic risk associated with hydroelectric generation when the facility commences operations.

Commodity Price Risk: The FortisBC Energy companies are exposed to commodity price risk associated with changes in the market price of natural gas. UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market prices of electricity and natural gas. The operation of regulator-approved deferral mechanisms to flow through in customer rates the cost of natural gas, purchased power and coal serves to mitigate the impact on earnings of commodity price volatility. The risks have also been reduced by entering into various price-risk management strategies to reduce exposure to commodity rates, including the use of derivative contracts that effectively fix the price of natural gas, power and electricity purchases. The absence of such hedging mechanism in the future could result in increased exposure to market price volatility.

Certain of the Corporation's regulated electric utilities are exposed to commodity price risk associated with changes in world oil prices, which affect the cost of fuel and purchased power. The risk is substantially mitigated by the utilities' ability to flow through to customers the cost of fuel and purchased power through base rates and/or the use of rate-stabilization and other mechanisms, as approved by the various regulatory authorities. The ability to flow through to customers the cost of fuel and purchased power alleviates the effect on earnings of the variability in the cost of fuel and purchased power.

There can be no assurance that the current regulator-approved mechanisms allowing for the flow through of the cost of natural gas, fuel, coal and purchased power will continue to exist in the future. Also, a severe and prolonged increase in such costs could materially affect the FortisBC Energy companies, UNS Energy and Central Hudson, despite regulatory measures available to compensate for changes in these costs. The inability of the regulated utilities to flow through the full cost of natural gas, fuel and/or purchased power could have a material adverse effect on the utilities' results of operations and financial position.

Derivative Instruments: From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates, and fuel, electricity and natural gas prices through the use of derivative instruments. The Corporation does not hold or issue derivative instruments for trading purposes and generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges. As at December 31, 2014, the Corporation's derivative instruments primarily consisted of electricity swap and power contracts, gas swap and option contracts, and gas purchase contract premiums.

Mark-to-market is the default accounting treatment for all derivative instruments unless they qualify, and are designated, for one of the elective accounting treatments. Mark-to-market requires the derivative instrument to be recorded at fair value, with changes in fair value recognized in earnings. As permitted by their respective regulators, UNS Energy, Central Hudson and the FortisBC Energy companies record unrealized gains and losses on certain derivative instruments as regulatory assets and liabilities for recovery, from or refund to, customers in future rates.

Foreign Exchange Risk: The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars. The reporting currency of UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos, BECOL and FortisUS Energy is the US dollar.

As at December 31, 2014, the Corporation's corporately issued US$1,496 million (December 31, 2013 - US$1,033 million) long-term debt had been designated as an effective hedge of the Corporation's foreign net investments. As at December 31, 2014, the Corporation had approximately US$2,762 million (December 31, 2013 - US$560 million) in foreign net investments remaining to be hedged. The Corporation's US dollar-denominated foreign net investments as at December 31, 2014 were significantly impacted by the UNS Energy acquisition, which was substantially financed through Convertible Debentures and preference shares denominated in Canadian dollars. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the balance sheet in accumulated other comprehensive income.

As a result of the acquisition of UNS Energy, consolidated earnings and cash flows of Fortis will be impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, it is estimated that a 5 cent, or 5%, increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CDN$1.16 as at December 31, 2014 would increase or decrease earnings per common share of Fortis by approximately 4 cents. Management will continue to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams, where possible, through future US dollar-denominated borrowings, and will continue to monitor the Corporation's exposure to foreign currency fluctuations on a regular basis.

Effective June 20, 2011, the Corporation's asset associated with its expropriated investment in Belize Electricity does not qualify for hedge accounting as Belize Electricity is no longer a foreign subsidiary of Fortis. As a result, foreign exchange gains and losses on the translation of the long-term other asset associated with Belize Electricity are recognized in earnings. In 2014 the Corporation recognized in earnings a foreign exchange gain of approximately $8 million (2013 - $6 million).

Counterparty Risk: UNS Energy, Central Hudson and the FortisBC Energy companies may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The above-noted utilities deal with credit quality institutions in accordance with established credit approval practices. These utilities did not experience any counterparty defaults in 2014 and do not expect any counterparties to fail to meet their obligations.

FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As required under regulation, FortisAlberta minimizes its gross exposure associated with retailer billings by obtaining from the retailer either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.

Competitiveness of Natural Gas in British Columbia: Prior to 2000, natural gas consistently enjoyed a substantial competitive advantage when compared with alternative sources of energy in British Columbia. However, since the majority of electricity prices in British Columbia were set based on the historical average cost of production, primarily associated with hydroelectric generation rather than based on market forces, the competitive advantage of natural gas was substantially eroded during the decade that followed. More recently, there has been upward pressure on electricity rates in British Columbia, largely due to new investment required in the electricity generation and transmission sectors. In addition, the growth in North American natural gas supply, primarily from shale gas production, has resulted in a lower natural gas price environment. These factors have helped to improve natural gas competitiveness on an operating basis. Nevertheless, differences in upfront capital costs between electric and natural gas equipment for hot water and space heating applications continue to present challenges for the competitiveness of natural gas on a full-cost basis.

Government policy has also impacted the competitiveness of natural gas in British Columbia. The Government of British Columbia has introduced changes to energy policy, including GHG emission reduction targets and a consumption tax on carbon-based fuels. The Government of British Columbia has yet to introduce a carbon tax on imported electricity generated through the combustion of carbon-based fuels. The impact of these changes in energy policy may have a material impact on the competitiveness of natural gas relative to non-carbon-based energy sources or other energy sources.

There are other competitive challenges impacting the penetration of natural gas in new housing supply, such as the green attributes of the energy source and the type of housing being built. In recent years, the FortisBC Energy companies have experienced a decline in the percentage of new homes installing natural gas compared with the total number of dwellings being built throughout British Columbia.

In the future, if natural gas becomes less competitive due to pricing or other factors, the ability of the FortisBC Energy companies to add new customers could be impaired, and existing customers could reduce their consumption of natural gas or eliminate its usage altogether as furnaces, water heaters and other appliances are replaced. The above conditions may result in higher customer rates and, in an extreme case, could ultimately lead to an inability of the FortisBC Energy companies to fully recover COS in rates charged to customers.

Refer also to the "Business Risk Management - Environmental Risks" section of this MD&A.

Natural Gas, Fuel and Electricity Supply: The FortisBC Energy companies are dependent on a limited selection of pipeline and storage providers, particularly in the Lower Mainland, Interior and Vancouver Island service areas. Regional market prices, particularly at the Sumas market hub, have been higher than prices elsewhere in North America during peak winter periods, when regional pipeline and storage resources become constrained in serving the demand for natural gas in British Columbia and the U.S. Pacific Northwest. In addition, the FortisBC Energy companies are highly dependent on a single-source transmission pipeline. In the event of a prolonged service disruption of the Spectra Pipeline System, residential customers of the FortisBC Energy companies could experience outages, thereby affecting revenue and also resulting in costs to safely relight customers. The LNG storage facility on Vancouver Island helps to reduce this risk by providing short-term on-system supply during cold weather conditions or emergency situations.

Developments are occurring in the region that may increase the demand for gas supply from British Columbia. These include an increase in pipeline capacity to deliver gas from British Columbia to markets outside of British Columbia and the potential development of large-scale LNG facilities to export gas to Asian markets. British Columbia has significant natural gas resources that are expected to be sufficient to meet incremental demand requirements and to continue to supply existing markets. It is uncertain at this time, however, how the pace and location of infrastructure development to connect production to new and existing markets could impact the Corporation's access to supply at fair market prices.

The UNS Utilities are dependent on third parties to supply fuel, including natural gas and coal. Disruption of fuel supply could impair the ability of the Companies to deliver electricity or gas or generate electricity and could adversely affect operations. In addition, a loss of coal suppliers or the inability to renew existing coal or natural gas contracts at favorable terms could significantly affect the ability to serve customers and adversely affect the financial condition and the results of operations of the UNS Utilities. In particular, the current coal supply contract for the San Juan generating station expires on December 31, 2017 and TEP and other San Juan owners are currently under negotiations concerning the future San Juan fuel supply. If an economic long-term coal supply agreement is unable to be secured, the continued operation of San Juan could be jeopardized, resulting in the retirement of San Juan Unit 1 earlier than expected.

Newfoundland Power is dependent on Newfoundland Hydro for approximately 93% of its customers' energy requirements and Maritime Electric is dependent on New Brunswick Power for approximately 80% of its customers' energy requirements. The Corporation's utilities in the Caribbean are dependent on third parties for the supply of all of their fuel requirements in the operation of their diesel-powered generating facilities. A shortage or interruption of the supply of electricity or fuel for the above utilities could have a material impact on their operations.

Newfoundland Power experienced losses of electricity supply from Newfoundland Hydro in January 2013 and January 2014, which interrupted power supply and resulted in significant outages. During 2014 the PUB commenced an inquiry and hearing process into the Island interconnected system supply issues and related power interruptions. As well, the Government of Newfoundland and Labrador has engaged consultants to complete an independent review of the current electricity system in the province. To the extent it is able, Newfoundland Power intends to participate in these reviews in 2015.

Future changes in supply costs at Newfoundland Power, including costs associated with Nalcor Energy's Muskrat Falls hydroelectric generation development and associated transmission assets, may affect electricity prices in a manner that affects the Newfoundland Power's sales.

Power Purchase and Capacity Sale Contracts: FortisBC Electric's indirect customers are directly served by the Company's wholesale customers, who themselves are municipal utilities. The municipal utilities may be able to obtain alternate sources of energy supply, which would result in decreased demand, higher customer rates and, in an extreme case, could ultimately lead to an inability by FortisBC Electric to fully recover its COS in rates charged to customers.

Additionally, the Corporation's regulated electric utilities periodically enter into various power purchase contracts and resale contracts for excess capacity with third parties. Upon expiry of the contracts, there is a risk that the utilities may not be able to secure extensions of such contracts. If the contracts are not extended, there is a risk of the utilities not being able to obtain alternate supplies of similarly priced electricity or not being able to secure additional capacity resale contracts. The utilities are also exposed to risk in the event of non-performance by counterparties to the various power purchase and resale contracts.

Employee Future Benefit Plan Performance and Funding Requirements: Fortis and the majority of its subsidiaries maintain a combination of defined benefit pension and/or OPEB plans for certain of their employees. Approximately 66% of the Corporation's total employees are members of defined benefit pension plans and approximately 84% of employees are members of OPEB plans.

The employee future benefit plans are subject to judgments utilized in the actuarial determination of the projected benefit obligation and related net benefit cost. The primary assumptions utilized by management are the expected long-term rate of return on assets, the discount rate and the health care trend rate used to value the projected benefit obligation. For a discussion of the critical accounting estimates associated with employee future benefit plans, refer to the "Critical Accounting Estimates - Employee Future Benefits" section of this MD&A.

The projected benefit obligation and related net benefit cost can be affected by changes in the global financial and capital markets. There is no assurance that the employee future benefit plan assets will earn the assumed long-term rates of return. Market-driven changes impacting the performance of the employee future benefit plan assets may result in material variations from the assumed long-term rates of return on the assets, which may cause material changes in future plan funding requirements from current estimates and future net benefit cost. Market-driven changes impacting the discount rates or the health care trend rate may also result in material changes in future plan funding requirements from current estimates and future net benefit cost.

There is also risk associated with measurement uncertainty inherent in the actuarial valuation process, as it affects the measurement of net benefit cost, future funding requirements and the projected benefit obligation.

At the regulated utilities, the above-noted risks are mitigated as any increase or decrease in future plan funding requirements and/or net benefit cost is expected to be recovered from, or refunded to, customers in future rates, subject to forecast risk. Additionally, at the FortisBC Energy companies, UNS Energy, Central Hudson, FortisBC Electric and Newfoundland Power, actual net benefit cost above or below forecast net benefit cost approved for recovery in customer rates for the year is also subject to deferral account treatment, subject to regulatory approval. There can be no assurance that the current regulator-approved deferral mechanisms will continue to exist in the future. An inability to flow through net benefit cost in customer rates could have a material adverse effect on the results of operations and financial position of the regulated utilities. The defined benefit pension plans at Central Hudson, FortisAlberta, Newfoundland Power and certain plans at FortisOntario are closed to all new employees. Central Hudson's OPEB plan is also closed to all new employees.

Jointly Owned and Operated Generating Units: Certain of the generating stations from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have the sole discretion or any ability to affect the management or operations at such facilities and therefore, may not be able to ensure the proper management of the operations and maintenance of the plants. Further, TEP may have limited or no discretion on managing the changing regulations which may affect such facilities. In addition, TEP will not have sole discretion as to how to proceed with environmental compliance requirements which could require significant capital expenditures or the closure of such generating stations. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such generating facilities could negatively impact the business and operations of TEP. In particular, TEP is subject to disagreement and litigation by third party owners with respect to the existing facility support agreement for Springerville Unit 1. This dispute could result in the refusal of third party owners to pay some or all of their pro rata share of such Springerville Unit 1 costs and expenses. For further details, refer to the "Critical Accounting Estimates - Contingencies" section of this MD&A.

Technology Developments in Distributed Generation and Energy Efficiency: New technology developments in distributed generation, particularly solar, and energy efficiency products and services, as well as the implementation of renewable energy and energy efficiency standards, will continue to have a significant impact on retail sales, which could negatively impact UNS Energy's results of operations, net earnings and cash flows. Heightened awareness of energy costs and environmental concerns have increased demand for products intended to reduce consumers' use of electricity. UNS Energy is promoting demand-side management programs designed to help customers reduce their energy usage.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy efficiency and more energy efficient appliances and equipment. Advances in these, or other technologies, could reduce the cost of producing electricity or make the existing facilities of UNS Energy less economical. In addition, advances in such technologies could reduce electrical demand, which could negatively impact the results of operations, net earnings and cash flows of TEP and UNS Electric.

Environmental Risks: The Corporation's electric and gas utilities are subject to inherent risks, including fires, contamination of air, soil or water from hazardous substances, natural gas emissions and emissions from the combustion of fuel required in the generation of electricity. Risks associated with fire damage are related to weather, the extent of forestation, habitation and third-party facilities located on or near the land on which the utilities' facilities are situated. The utilities may become liable for fire-suppression costs, regeneration and timber value costs, and third-party claims in connection with fires on land on which its facilities are located if it is found that such facilities were the cause of a fire, and such claims, if successful, could be material. Risks also include the responsibility for remediation of contaminated properties, whether or not such contamination was actually caused by the property owner. The risk of contamination of air, soil and water at the electric utilities primarily relates to the transportation, handling and storage of large volumes of fuel, the use and/or disposal of petroleum-based products, mainly transformer and lubricating oil, in the utilities' day-to-day operating and maintenance activities, and emissions from the combustion of fuel required in the generation of electricity, mainly at the Corporation's regulated utilities in the Caribbean. The risk of contamination of air, soil or water at the natural gas utilities primarily relates to natural gas and propane leaks and other accidents involving these substances. Additional risks include environmental reclamation associated with coal mines that supply generating stations in which the Corporation has an ownership interest.

The management of GHG emissions is a specific environmental concern of the Corporation's regulated gas utilities in Canada and the United States, primarily due to new and emerging federal, provincial and state GHG laws, regulations and guidelines. In British Columbia, the Government of British Columbia's Energy Plan, Carbon Tax Act, Clean Energy Act, Greenhouse Gas Reduction (Cap and Trade) Act and Greenhouse Gas Reduction Targets Act affect, or may potentially affect, the operations of the FortisBC Energy companies and FortisBC Electric. The Energy Plan contains a strong focus on environmental leadership, energy conservation and efficiency, and investing in innovation. Many of the principles of the Energy Plan were incorporated into the regulatory framework in British Columbia upon the British Columbia Legislature passing the Utilities Commission Amendment Act, 2008 and passing the Clean Energy Act. The Clean Energy Act, which establishes a long-term vision for the province as a leader in clean energy development, came into force in June 2010. FortisBC Electric and the FortisBC Energy companies continue to assess and monitor the impact the Energy Plan and the Clean Energy Act may have on future operations. Energy to be produced by the Waneta Expansion in British Columbia, upon its completion, is consistent with the objective under the Clean Energy Act to reduce GHG emissions. In 2011 the FortisBC Energy companies began reporting their GHG emissions pursuant to the reporting regulation under the Greenhouse Gas Reduction (Cap and Trade) Act. In addition, the FortisBC Energy companies continue to report their GHG emissions under Environment Canada's GHG Reporting Program. The FortisBC Energy companies have developed capabilities that will support the management of compliance requirements in an upcoming GHG emissions' trading environment, as government policy in that area evolves. The Companies will also continue to monitor and assess emerging regulations, in particular, the offset and allowance regulations.

In the United States, the Environmental Protection Agency ("EPA") proposed carbon emission standards in June 2014 to reduce GHG emissions from existing power plants. The EPA's proposal for Arizona would result in a significant shift in generation from coal to natural gas and renewables and could lead to the early retirement of coal generation in Arizona by 2020. The EPA is expected to finalize those standards by summer 2015. These proposed regulations would, if adopted in the form proposed, result in a change in the composition of TEP's generating fleet. As at January 1, 2015, approximately 54% of TEP's generating capacity is fuelled by coal. The final rule issued by the EPA could significantly impair the ability to operate certain of TEP's coal-fired generation plants on an economically viable basis or at all. A substantial change in TEP's generation portfolio could result in increased cost of operations and/or additional capital investments. The impact of final regulations to address global climate change will depend on the specific terms of those measures and cannot be determined at this time.

If any of the coal-fired generation plants, or coal handling facilities, from which TEP obtains power are closed prior to the end of their useful life, TEP could be required to recognize a material impairment of its assets and incur added expenses relating to accelerated depreciation and amortization, decommissioning and cancellation of long-term coal contracts of such generating plants and facilities. Closure of any of such generating stations may force TEP to incur higher costs for replacement capacity and energy. TEP may not be permitted recovery of these costs in the rates it charges its customers. In addition, early closures of certain generating units could require UNS Energy to redeem some or all tax-exempt bonds associated with the respective generating units.

The United Kingdom's ratification of the United Nations Framework Convention on Climate Change and its Kyoto Protocol were extended to the Cayman Islands in 2007. This framework aims to reduce GHG emissions produced by certain industries. Specific details of the regulations implementing the protocol have yet to be released by the local government of the Cayman Islands and, accordingly, Caribbean Utilities is currently unable to assess the financial impact of compliance with the framework of the protocol.

The key environmental hazards related to hydroelectric generation operations include the creation of artificial water flows that may disrupt natural habitats and the storage of large volumes of water for the purpose of electricity generation.

The trend in environmental regulation has been to impose more restrictions and limitations on activities that may impact the environment, including the generation and disposal of wastes, the use and handling of chemical substances, and the requirement for environmental impact assessments and remediation work. It is possible that other developments may lead to increasingly strict environmental laws and enforcement policies, and claims for damages to property or persons resulting from the operations of the Corporation's subsidiaries, any one of which could result in substantial costs or liabilities to the subsidiaries.

While the Corporation and its subsidiaries maintain insurance, there can be no assurance that all possible types of liabilities that may arise related to environmental matters will be covered by insurance. For further information, refer to the "Business Risk Management - Insurance Coverage Risk" section of this MD&A.

The Corporation and its subsidiaries are subject to numerous federal, state and provincial laws, regulations and guidelines governing the generation, management, storage, transportation, recycling and disposal of hazardous substances and other waste materials and otherwise relating to the protection of the environment. These laws and regulations can contribute to higher capital, operating and other costs. Existing environmental laws and regulations may be revised or new environmental laws and regulations may be adopted or become applicable to the Corporation's operations. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adverse effect on the results of operations of the Corporation. The utilities would request that additional costs resulting from environmental laws and regulation be recovered from customers in future rates. In addition, the process of obtaining environmental permits and approvals, including any necessary environmental assessments, can be lengthy, contentious and expensive. The Corporation believes that it and its subsidiaries are materially compliant with the environmental laws, regulations and guidelines applicable to them in the various jurisdictions in which they operate.

TEP is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stations in which it has an ownership interest and is obligated to pay similar costs at the coal mines that supply these generating stations. As at December 31, 2014, TEP has recognized approximately US$22 million in mine reclamation obligations, representing the present value of the estimated future liability. While TEP has recorded the portion of its obligations for such reclamation costs that can be determined at this time, the total costs and timing of final reclamation at these sites are unknown and could be substantial. TEP recovers final mine reclamation costs through regulator-approved mechanisms as costs are paid to the coal suppliers.

Central Hudson is exposed to environmental contingencies associated with manufactured gas plants ("MGPs") that it and its predecessors owned and operated to serve their customers' heating and lighting needs from the mid-to-late 1800s to the 1950s. The New York State Department of Environmental Conservation ("DEC") regulates the timing and extent of remediation of MGP sites in New York State. As at December 31, 2014, Central Hudson has recognized approximately US$105 million in associated MGP environmental remediation liabilities. As approved by the PSC, the Company is currently permitted to recover MGP site investigation and remediation costs in customer rates.

With the exception of the mine reclamation costs at TEP and the MGP remediation liabilities at Central Hudson as noted above, as at December 31, 2014, there were no material environmental liabilities recognized in the Corporation's 2014 Audited Consolidated Financial Statements. Also, there were no material unrecorded environmental liabilities known to management, except for the possibility of liabilities associated with various contingencies as discussed in the "Critical Accounting Estimates - Contingencies" section of this MD&A. The regulated utilities would seek to recover in customer rates the costs associated with environmental protection, compliance or damages; however, there is no assurance that the regulators would agree with the utilities' requests and, therefore, unrecovered costs, if substantial, could have a material adverse effect on the results of operations and financial position of the utilities.

From time to time, it is possible that the Corporation and its subsidiaries may become subject to government orders, investigations, inquiries or other proceedings relating to environmental matters. The occurrence of any of these events, or any changes in applicable environmental laws, regulations and guidelines, or their enforcement or regulatory interpretation, could materially impact the results of operations and financial position of the Corporation and its subsidiaries.

Each of the utilities owned by Fortis has an Environmental Management System ("EMS"), with the exception of UNS Energy, which relies upon a comprehensive set of environmental protocols. Environmental policies form the cornerstone of the EMS and environmental protocols, and outline the following commitments by each utility and its employees with respect to conducting business in a safe and environmentally responsible manner: (i) meet and comply with all applicable laws, legislation, policies, regulations and accepted standards of environmental protection; (ii) manage activities consistent with industry practice and in support of the environmental policies of all levels of government; (iii) identify and manage risks to prevent or reduce adverse consequences from operations, including preventing pollution and conserving natural resources; (iv) regularly conduct environmental monitoring and audits of the EMS and environmental protocols and strive for continual improvement in environmental performance; (v) regularly set and review environmental objectives, targets and programs; (vi) communicate openly with stakeholders, including making available the utility's environmental policy and knowledge of environmental issues to customers, employees, contractors and the general public; (vii) support and participate in community-based projects that focus on the environment; (viii) provide training for employees and those working on behalf of the utility to enable them to fulfill their duties in an environmentally responsible manner; and (ix) work with industry associations, government and other stakeholders to establish standards for the environment appropriate to the utility's business.

During 2014 direct costs arising from environmental protection, compliance, damages and the carrying out of EMS and environmental protocol responsibilities did not have a material impact on the Corporation's consolidated results of operations, cash flows or financial position. Many of the above costs, however, are embedded in the utilities' operating, maintenance and capital programs and are, therefore, not readily identifiable.

Insurance Coverage Risk: The Corporation and its subsidiaries maintain insurance with respect to potential liabilities and the accidental loss of value of certain of their assets, for amounts and with such insurers as is considered appropriate, taking into account all relevant factors, including practices of owners of similar assets and operations. However, a significant portion of the Corporation's regulated electric utilities' T&D assets is not covered under insurance, as is customary in North America, as the cost of coverage is not considered economically viable. Insurance is subject to coverage limits as well as time-sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities that may be incurred by the Corporation and its subsidiaries will be covered by insurance. The Corporation's regulated utilities would likely apply to their respective regulatory authority to recover any loss or liability through increased customer rates. However, there can be no assurance that a regulatory authority would approve any such application in whole, or in part. Any major damage to the physical assets of the Corporation and its subsidiaries could result in repair costs, lost revenue and customer claims that are substantial in amount and which could have a material adverse effect on the Corporation's results of operations, cash flows and financial position. In addition, the occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by the Corporation and its subsidiaries, or claims that fall within a significant self-insured retention could have a material adverse effect on the Corporation's results of operations, cash flows and financial position.

It is anticipated that insurance coverage will be maintained. However, there can be no assurance that the Corporation and its subsidiaries will be able to obtain or maintain adequate insurance in the future at rates considered reasonable, or that insurance will continue to be available on terms as favourable as the existing arrangements, or that the insurance companies will meet their obligations to pay claims.

Loss of Licences and Permits: The acquisition, ownership and operation of electric and gas utilities and assets require numerous licences, permits, approvals and certificates ("Approvals") from various levels of government, government agencies and third parties. For various reasons, including increased stakeholder participation, the Corporation's regulated utilities and non-regulated generation operations may not be able to obtain or maintain all required Approvals. If there is a delay in obtaining any required Approvals, or if there is a failure to obtain or maintain any required Approvals or to comply with any applicable law, regulation or condition of an approval, the operation of the assets and the sale of electricity and gas could be prevented or become subject to additional costs, any of which could have a material adverse effect on the Corporation's subsidiaries.

FortisBC Electric's ability to generate electricity from its facilities on the Kootenay River and to receive its entitlement of capacity and energy under the Canal Plant Agreement depends upon the maintenance of its water licences issued under the Water Act (British Columbia). In addition, water flows on the Kootenay River are governed under the terms of the Columbia River Treaty between Canada and the United States, as well as the International Joint Commission's Order for Kootenay Lake. Government authorities in Canada and the United States have the power under the treaty and the International Joint Commission's Order to regulate water flows to protect environmental standards in a manner that could adversely affect the amount of water available for the generation of power.

Loss of Service Area: FortisAlberta serves customers residing within various municipalities throughout its service areas. From time to time, municipal governments in Alberta give consideration to creating their own electric distribution utilities by purchasing the assets of FortisAlberta located within their municipal boundaries. Upon the termination, or in the absence, of a franchise agreement, a municipality has the right, subject to AUC approval, to purchase FortisAlberta's assets within its municipal boundaries pursuant to the Municipal Government Act (Alberta), with the price to be as agreed by the Company and the municipality, failing which it is to be determined by the AUC. Additionally, under the Hydro and Electric Energy Act (Alberta), if a municipality that owns an electric distribution system expands its boundaries, it can acquire FortisAlberta's assets in the annexed area. In such circumstances, the Hydro and Electric Energy Act (Alberta) provides that the AUC may determine that the municipality should pay compensation to the Company for any facilities transferred on the basis of replacement cost less depreciation. Given the historical population and economic growth of Alberta and its municipalities, FortisAlberta is affected by transactions of this type from time to time.

The consequence to FortisAlberta of a municipality purchasing its distribution assets would be an erosion of the Company's rate base, which would reduce the capital upon which FortisAlberta could earn a regulated return. This reduction of rate base could have a material adverse effect on the results of operations and financial position of FortisAlberta.

Continued Reporting in Accordance with US GAAP: In January 2014 the Ontario Securities Commission ("OSC") issued a relief order which permits the Corporation and its reporting issuer subsidiaries to continue to prepare their financial statements in accordance with US GAAP until the earliest of: (i) January 1, 2019; (ii) the first day of the financial year that commences after the Corporation or its reporting issuer subsidiaries ceases to have activities subject to rate regulation; or (iii) the effective date prescribed by the International Accounting Standards Board ("IASB") for the mandatory application of a standard within International Financial Reporting Standards ("IFRS") specific to entities with activities subject to rate regulation.

If the OSC relief does not continue as detailed above, the Corporation and its reporting issuer subsidiaries would then be required to become U.S. Securities and Exchange Commission issuers in order to continue reporting under US GAAP, or adopt IFRS. The IASB has released an interim, optional standard on Regulatory Deferral Accounts and continues to work on a project focusing on accounting specific to rate-regulated activities. It is not yet known when this project will be completed or whether IFRS will, as a result, include a permanent, mandatory standard to be applied by entities with activities subject to rate regulation. In the absence of a permanent standard for rate-regulated activities, the application of IFRS at that time could result in volatility in the Corporation's earnings and earnings per common share as compared to those which would otherwise be recognized under US GAAP.

Changes in Tax Legislation: In December 2014 Bill C-43, Economic Action Plan 2014 Act, No. 2 received Royal Assent and was passed into legislation in Canada. This Bill contains an amendment to the foreign accrual property income ("FAPI") rules as it pertains to the definition of "non-qualifying country", and excludes countries, such as Belize, who are members of the Convention of Mutual Assistance in Tax Matters from the definition of "non-qualifying country". Before this change, countries that had not entered into a Tax Information Exchange Agreement ("TIEA") with Canada would be required to report active business income earned in a foreign country as FAPI, as if the income had been earned in Canada. The five-year timetable to conclude TIEA negotiations with the GOB will be reached in June 2015; however this new legislation will eliminate any impact on Fortis if a TIEA is not put into effect by the deadline.

Repatriation of capital legislation also introduced changes of how earnings can be repatriated to Canada. Canada requires the governments of certain tax-free jurisdictions to enter a TIEA to access the new repatriation rules. Once in force, the TIEA will permit dividends paid out of active business income to be exempted from tax when received in Canada. Also, this legislation will allow Fortis to receive a tax-free return of capital from the Caribbean. These changes provide a mechanism to repay the upstream loans, thereby allowing the Corporation to comply with the above legislative changes.

In June 2013 Canada enacted legislation relating to upstream loans and the repatriation of capital. The Corporation has approximately $66 million of upstream loans from its Caribbean subsidiaries. Fortis used these upstream interest-free loans as a tax-deferred repatriation of earnings. This legislation provided a special transition rule for loans that were in place on August 19, 2011. All of the Corporation's upstream loans were in place on August 19, 2011 and qualify for the special transition rule.

Any future changes in other tax legislation could materially affect the Corporation's consolidated earnings.

Access to First Nations' Lands: The FortisBC Energy companies and FortisBC Electric provide service to customers on First Nations' lands and maintain gas facilities and electric generation and T&D facilities on lands that are subject to land claims by various First Nations. A treaty negotiation process involving various First Nations and the governments of British Columbia and Canada is underway, but the basis upon which settlements might be reached in the service areas of the FortisBC Energy companies and FortisBC Electric is not clear. Furthermore, not all First Nations are participating in the process. To date, the policy of the Government of British Columbia has been to endeavour to structure settlements without prejudicing existing rights held by third parties, such as the FortisBC Energy companies and FortisBC Electric. However, there can be no certainty that the settlement process will not have a material adverse effect on the FortisBC Energy companies' and FortisBC Electric's results of operations and financial position.

The Supreme Court of Canada decided in 2010 that, before issuing regulatory approvals for the addition of new facilities, the BCUC must consider whether the Crown has a duty to consult and accommodate First Nations, if necessary, and if so, whether the consultation and accommodation by the Crown have been adequate. This may affect the timing, cost and likelihood of the BCUC's approval of certain capital projects of the FortisBC Energy companies and FortisBC Electric.

FortisAlberta has distribution assets on First Nations' lands with access permits to these lands held by TransAlta Utilities Corporation ("TransAlta"). In order for FortisAlberta to acquire these access permits, both the Department of Aboriginal Affairs and Northern Development Canada and the individual First Nations band councils must grant approval. FortisAlberta may not be able to acquire the access permits from TransAlta and may be unable to negotiate land-use agreements with property owners or, if negotiated, such agreements may be on terms that are less than favourable to FortisAlberta and, therefore, may have a material adverse effect on FortisAlberta.

Labour Relations Risk: The Corporation's subsidiaries employ members of labour unions or associations that have entered into collective bargaining agreements with the subsidiaries. The Corporation considers the relationships of its subsidiaries with their labour unions and associations to be satisfactory but there can be no assurance that current relations will continue in the future or that the terms under the present collective bargaining agreements will be renewed. The inability to maintain or renew the collective bargaining agreements on acceptable terms could result in increased labour costs or service interruptions arising from labour disputes that are not provided for in approved rate orders at the regulated utilities and which could have a material adverse effect on the results of operations, cash flows and financial position of the utilities.

The collective agreement between FortisBC Electric and International Brotherhood of Electrical Workers ("IBEW") expired on January 31, 2013. IBEW represents employees in specified occupations in the areas of generation and T&D. In December 2013, following a labour disruption, the IBEW and FortisBC Electric agreed to binding interest arbitration. The arbitration process was completed in June 2014 and the arbitrator's decision was received in November 2014, resulting in a collective agreement expiring on January 31, 2018.

The collective agreement between the FortisBC Energy companies and IBEW was renewed in 2014 and now expires on March 31, 2019. IBEW represents employees in specified occupations in the areas of T&D.

The collective agreements between the FortisBC Energy companies and Canadian Office and Professional Employees Union ("COPE") and FortisBC Electric and COPE representing customer service employees expired on March 31, 2014. The collective agreements have been renewed for three-year periods expiring on March 31, 2017. The FortisBC Energy companies have a second collective agreement with COPE, representing employees in specified occupations in the areas of administration and operations, which expires in March 2015.

The two collective agreements between Newfoundland Power and IBEW expired on September 30, 2014. The Company and IBEW reached a tentative agreement in December 2014, subject to ratification by the members.

Human Resources Risk: The ability of Fortis to deliver service in a cost-effective manner is dependent on the ability of the Corporation's subsidiaries to attract, develop and retain skilled workforces. Like other utilities across Canada and in the United States and the Caribbean, the Corporation's utilities are faced with demographic challenges relating to trades, technical staff and engineers. The growing size of the Corporation and a competitive job market present ongoing recruitment challenges. The Corporation's significant consolidated capital expenditure program will present challenges to ensure the Corporation's utilities have the qualified workforce necessary to complete the capital work initiatives.

CHANGES IN ACCOUNTING POLICIES

The new US GAAP accounting policies that are applicable to, and were adopted by, Fortis, effective January 1, 2014, are described as follows.

Obligations Resulting from Joint and Several Liability Arrangements

The Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 405, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, as outlined in Accounting Standards Update ("ASU") No. 2013-04. The amendments were applied by the Corporation retrospectively and did not materially impact the Corporation's 2014 Audited Consolidated Financial Statements.

Parent's Accounting for the Cumulative Translation Adjustment

The Corporation adopted the amendments to ASC Topic 830, Foreign Currency Matters - Parent's Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity, as outlined in ASU No. 2013-05. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's 2014 Audited Consolidated Financial Statements.

Presentation of an Unrecognized Tax Benefit

The Corporation adopted the amendments to ASC Topic 740, Income Taxes - Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, as outlined in ASU No. 2013-11. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's 2014 Audited Consolidated Financial Statements.

FUTURE ACCOUNTING PRONOUNCEMENTS

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014 the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendments in this update change the requirements for reporting discontinued operations and require additional disclosures about discontinued operations. This update is effective for annual and interim periods beginning on or after December 15, 2014 and is to be applied prospectively. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.

Revenue from Contracts with Customers

In May 2014 FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. The amendments in this update create ASC Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard completes a joint effort by FASB and the International Accounting Standards Board to improve financial reporting by creating common revenue recognition guidance for US GAAP and International Financial Reporting Standards that clarifies the principles for recognizing revenue and that can be applied consistently across various transactions, industries and capital markets. This standard is effective for annual and interim periods beginning on or after December 15, 2016 and is to be applied on a full retrospective or modified retrospective basis. Early adoption is not permitted. Fortis is assessing the impact that the adoption of this standard will have on its consolidated financial statements. The Corporation and its subsidiaries are in the process of identifying contracts with customers and performance obligations in the contracts.

Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period

In June 2014 FASB issued ASU No. 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. The amendments in this update are intended to resolve diversity in practice for employee share-based payments with performance targets that can entitle an employee to benefit from an award regardless of if they are rendering services at the date the performance target is achieved. This update is effective for annual and interim periods beginning on or after December 15, 2015 and may be applied prospectively or retrospectively. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.

Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern

In August 2014 FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The amendments in this update are intended to provide guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning on or after December 15, 2016. Early adoption is permitted. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.

FINANCIAL INSTRUMENTS

The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.

Financial Instruments 2014 2013
As at December 31 Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
Waneta Partnership promissory note 53 56 50 50
Long-term debt, including current portion 10,501 12,237 7,204 8,084

The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.

The Financial Instruments table above excludes the long-term other asset associated with the Corporation's expropriated investment in Belize Electricity. Due to uncertainty in the ultimate amount and ability of the GOB to pay appropriate fair value compensation owing to Fortis for the expropriation of Belize Electricity, the Corporation has recorded the book value of the expropriated investment, including foreign exchange impacts, in long-term other assets, which totalled approximately $116 million as at December 31, 2014 (December 31, 2013 - $108 million).

The following table presents, by level within the fair value hierarchy, the Corporation's assets and liabilities accounted for at fair value on a reoccurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement and there were no transfers between the levels in the periods presented. For derivative instruments, the Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions.

Financial Instruments Carried at Fair Value
As at December 31 Fair value
($ millions) hierarchy 2014 2013
Assets
Energy contracts subject to regulatory deferral (1) (2) Level 3 3 10
Energy contracts not subject to regulatory deferral (1) (2) Level 3 1 -
Other investments (3) Levels 1/2 36 6
Total gross assets 40 16
Less: Counterparty netting not offset on the balance sheet (4) (3 ) -
Total net assets 37 16
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (5) Levels 1/2/3 72 15
Energy contracts not subject to regulatory deferral (2) Level 3 1 -
Energy contracts - cash flow hedges (2) (6) Level 3 1 -
Interest rate swaps - cash flow hedges (6) Level 2 5 -
Total gross liabilities 79 15
Less: Counterparty netting not offset on the balance sheet (4) (3 ) -
Total net liabilities 76 15
(1) The fair value of the Corporation's energy contracts are recorded in accounts receivable and other current assets, long-term other assets, accounts payable and other current liabilities and long-term other liabilities. Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in rates as permitted by the regulators, with the exception of long-term energy sales contracts.
(2) Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude and direction of the change for each input. The impacts of changes in fair value are subject to regulatory recovery, with the exception of long-term energy sales contracts.
(3) Included in long-term other assets on the consolidated balance sheet and includes $5 million - level 1 and $31 million - level 2 (2013 - $6 million - level 1)
(4) Certain energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk and netted by counterparty where the intent and legal right to offset exists.
(5) Includes $2 million - level 1, $35 million - level 2 and $35 million - level 3 (2013 - $15 million - level 2)
(6) The fair value of certain of the Corporation's energy contracts are recorded in accounts payable and other current liabilities and the fair value of the Corporation's interest rate swaps are recorded in accounts payable and other current liabilities and long-term other liabilities. Unrealized gains and losses arising from changes in fair value are recorded in other comprehensive income until they become realized and are reclassified to earnings.

Derivative Instruments

The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges. The Corporation is required to record all derivative instruments at fair value, except for those that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments are estimates of the amounts that the utilities would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.

Energy Contracts Subject to Regulatory Deferral

UNS Energy holds electricity power purchase contracts and gas swap and option contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships and transmission and line losses. The fair value of gas swap and option contracts are estimated using a Black-Scholes option-pricing model, which includes inputs such as implied volatility, interest rates, and forward price curves. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.

Central Hudson holds electricity swap contracts and gas swap and option contracts to minimize commodity price volatility for electricity and natural gas purchases by fixing the effective purchase price for the defined commodities. The fair value of the electricity swap contracts and gas swap and option contracts was calculated using forward pricing provided by independent third parties.

The FortisBC Energy companies hold gas swap and option contracts and gas purchase contract premiums to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on market prices and forward curves for the cost of natural gas.

As at December 31, 2014, these energy contract derivatives were not designated as hedges; however, any unrealized gains or losses associated with changes in the fair value of the derivatives are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. These unrealized losses and gains would otherwise be recorded in earnings. As at December 31, 2014, unrealized losses of $69 million (December 31, 2013 - $15 million) were recognized in current regulatory assets and no unrealized gains were recognized in regulatory liabilities (December 31, 2013 - $10 million).

Energy Contracts Not Subject to Regulatory Deferral

From time to time, UNS Energy enters into forward contracts with long-term wholesale customers that qualify as derivative instruments. The fair value of power sales contracts is determined using observable market variables, regional power and gas prices, as well as the ratio between the two, and the prevailing market heat rate. The unrealized gains and losses on these derivative instruments are recorded in earnings, as they do not qualify for regulatory deferral. In December 2014 TEP entered into a three-year sales option contract and unrealized gains of less than $1 million associated with this contract were recognized in 2014.

Cash Flow Hedges

UNS Energy holds interest rate swaps, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on debt, and a power purchase swap, expiring in September 2015, to hedge the cash flow risk associated with a long-term power supply agreement. The after-tax unrealized gains and losses on cash flow hedges are recorded in other comprehensive income and reclassified to earnings as they become realized. The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately $3 million.

Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows.

Volume of Derivative Activity

As at December 31, 2014, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

Maturity Contracts
Volume (year) (#) 2015 2016 2017
Energy contracts subject to regulatory deferral:
Electricity swap contracts (GWh) 2017 7 1,200 659 219
Electricity power purchase contracts (GWh) 2017 33 1,206 457 145
Gas swap and option contracts (PJ) 2017 188 49 9 4
Gas purchase contract premiums (PJ) 2015 54 75 - -
Energy contracts not subject to regulatory deferral:
Long-term power sales contracts (GWh) 2017 1 536 586 634
Energy contracts - cash flow hedges (GWh) 2015 1 59 - -

The fair values of the derivative contracts are estimates of the amounts that the utilities would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates. The changes in the fair values of the derivative contracts are primarily deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators.

The fair values of the Corporation's financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flows.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation's consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. The Corporation's critical accounting estimates are discussed as follows.

Regulation: Generally, the accounting policies of the Corporation's regulated utilities are subject to examination and approval by the respective regulatory authority. Regulatory assets and regulatory liabilities arise as a result of the rate-setting process at the regulated utilities and have been recognized based on previous, existing or expected regulatory orders or decisions. Certain estimates are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. The final amounts approved by the regulatory authorities for deferral as regulatory assets and regulatory liabilities and the approved recovery or settlement periods may differ from those originally expected. Any resulting adjustments to original estimates are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.

As at December 31, 2014, Fortis recognized a total of $2,525 million in regulatory assets (December 31, 2013 - $1,822 million) and $1,555 million in regulatory liabilities (December 31, 2013 - $1,042 million).

For a further discussion of the nature of regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.

Depreciation and Amortization: Depreciation and amortization are estimates based primarily on the useful life of assets. Estimated useful lives are based on current facts and historical information and take into consideration the anticipated physical life of the assets. As at December 31, 2014, the Corporation's consolidated utility capital assets, non-utility capital assets and intangible assets were approximately $18.3 billion, or approximately 69%, of total consolidated assets compared to approximately $12.6 billion, or approximately 70%, of total consolidated assets as at December 31, 2013. The increase in capital assets was primarily due to the acquisition of UNS Energy and capital expenditures of approximately $1.7 billion in 2014. Depreciation and amortization was $688 million for 2014 compared to $541 million for 2013. Changes in depreciation rates may have a significant impact on the Corporation's consolidated depreciation and amortization expense.

As part of the customer rate-setting process at the Corporation's regulated utilities, appropriate depreciation and amortization rates are approved by the respective regulatory authority. The depreciation periods used and the associated rates are reviewed on an ongoing basis to ensure they continue to be appropriate. From time to time, third-party depreciation studies are performed at the regulated utilities. Based on the results of these depreciation studies, the impact of any over- or under-depreciation, as a result of actual experience differing from that expected and provided for in previous depreciation rates, is generally reflected in future depreciation rates and depreciation expense, when the differences are refunded or collected in customer rates, as approved by the regulator.

As required by their respective regulator, UNS Energy, Central Hudson, the FortisBC Energy companies, FortisAlberta, Newfoundland Power and Maritime Electric accrue estimated non-ARO removal costs in depreciation with the amount provided for in depreciation recorded as a long-term regulatory liability. Actual non-ARO removal costs, net of salvage proceeds, are recorded against the regulatory liability when incurred. The estimate of non-ARO removal costs is based on historical experience and expected cost trends. The balance of this regulatory liability as at December 31, 2014 was $951 million, an increase of $388 million from $563 million as at December 31, 2013, mainly due to the acquisition of UNS Energy. The total amount of non-ARO removal costs accrued and recognized in depreciation expense during 2014 was $88 million (2013 - $73 million).

Income Taxes: Income taxes are determined based on estimates of the Corporation's current income taxes and estimates of deferred income taxes resulting from temporary differences between the carrying values of assets and liabilities in the consolidated financial statements and their tax values. A deferred income tax asset or liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. Deferred income tax assets are assessed for the likelihood that they will be recovered from future taxable income. To the extent recovery is not considered more likely than not, a valuation allowance is recognized against earnings in the period when the allowance is created or revised. Estimates of the provision for current income taxes, deferred income tax assets and liabilities, and any related valuation allowance, might vary from actual amounts incurred.

Assessment for Impairment of Goodwill and Indefinite-Lived Intangible Assets: The Corporation is required to perform, at least on an annual basis, an impairment test for goodwill and indefinite-lived intangible assets, and any impairment provision is charged to earnings. The annual impairment test is performed as at October 1. In addition, the Corporation also performs an impairment test if any event occurs or if circumstances change that would indicate that the fair value of an operating unit was below its carrying value. No such event or change in circumstances occurred during 2014 or 2013.

As at December 31, 2014, consolidated goodwill totalled approximately $3.7 billion (December 31, 2013 - $2.1 billion). As a result of the acquisition of UNS Energy in 2014, additional goodwill of approximately $1.5 billion was recognized. Indefinite-lived intangible assets, not subject to amortization, consist of certain land, transmission and water rights and totalled approximately $68 million as at December 31, 2014 (December 31, 2013 - $66 million).

Fortis performs an annual internal quantitative assessment for each operating unit. For those operating units where: (i) management's assessment of quantitative and qualitative factors indicates that fair value is not 50% or more likely to be greater than carrying value; or (ii) the excess of estimated fair value over carrying value, as determined by an independent external consultant as of the date of the immediately preceding impairment test, was not significant, then fair value of the operating unit will be estimated by an independent external consultant in the current year. Irrespective of the above-noted approach, an operating unit to which goodwill has been allocated may have its fair value estimated by an independent external consultant as at the annual impairment date, as Fortis will, at a minimum, have fair value for each operating unit estimated by an independent external consultant once every three years.

In calculating goodwill impairment, Fortis determines those operating units that will have fair value estimated by an independent external consultant, as described above, and such estimated fair value is then compared to the book value of the applicable operating units. If the fair value of the operating unit is less than the book value, then a second measurement step is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the operating unit's assets and liabilities from the fair value of the operating unit to determine the implied fair value of goodwill, and then comparing that amount to the book value of the operating unit's goodwill. Any excess of the book value of the goodwill over the implied fair value is the impairment amount recognized.

The primary method for estimating fair value of the operating units is the income approach, whereby net cash flow projections for the operating units are discounted using an enterprise value approach. Under the enterprise value approach, sustainable cash flow is determined on an after-tax basis, prior to the deduction of interest expense, and is then discounted at the weighted average cost of capital to yield the value of the enterprise. An enterprise value approach does not assess the appropriateness of the operating unit's existing debt level. The estimated fair value of the operating unit is then determined by subtracting the fair value of the operating unit's interest-bearing debt from the enterprise value of the operating unit. A secondary valuation method, the market approach, is also performed by an independent external consultant as a check on the conclusions reached under the income approach. The market approach includes comparing various valuation multiples underlying the discounted cash flow analysis of the applicable operating units to trading multiples of guideline entities and recent transactions involving guideline entities, recognizing differences in growth expectations, product mix and risks of those guideline entities with the applicable operating units.

No impairment provisions were required in either 2014 or 2013 with respect to goodwill or indefinite-lived intangible assets.

Employee Future Benefits:

Defined Benefit Pension Plans

The Corporation's and subsidiaries' defined benefit pension plans are subject to judgments utilized in the actuarial determination of the net benefit cost and related obligation. The main assumptions utilized by management in determining the net benefit cost and obligation are the discount rate for the benefit obligation and the expected long-term rate of return on plan assets.

The expected weighted average long-term rate of return on the defined benefit pension plan assets, for the purpose of estimating net pension cost for 2015, is 6.36%, which is down from 6.46% used for 2014. The decrease in the average long-term rate of return reflects shifting of plan assets from equities to fixed income assets. The defined benefit pension plan assets experienced total positive returns of approximately $236 million in 2014 compared to expected positive returns of $106 million. The expected long-term rates of return on pension plan assets are developed by management with assistance from independent actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.

The assumed weighted average discount rate used to measure the projected benefit obligations as at December 31, 2014, and to determine net pension cost for 2015, is 4.00%, compared to the assumed weighted average discount rate used to measure the projected benefit obligations as at December 31, 2013, and to determine net pension cost for 2014, of 4.81%. The decrease in the assumed weighted average discount rate reflects lower yields on investment-grade corporate bonds. Discount rates reflect market interest rates on high-quality bonds with cash flows that match the timing and amount of expected pension payments. The methodology in determining the discount rates was consistent with that used to determine the discount rates in the previous year.

There was a $17 million increase in consolidated defined benefit net pension cost for 2014 compared to 2013, mainly due to the acquisition of UNS Energy in 2014 and Central Hudson in 2013. Excluding UNS Energy and Central Hudson, increased costs resulted from higher regulatory adjustments, partially offset by the amortization of lower actuarial losses, due to higher discount rates assumed. Any increases in defined benefit net pension cost at the regulated utilities for 2015 are expected to be recovered from customers in rates, subject to forecast risk at those utilities with smaller defined benefit plans.

The following table provides the sensitivities associated with a 100 basis point change in the expected long-term rate of return on pension plan assets and the discount rate on 2014 net benefit pension cost, and the related projected benefit obligation recognized in the Corporation's 2014 Audited Consolidated Financial Statements.

Sensitivity Analysis of Changes in Rate of Return on Plan Assets and Discount Rate
Year Ended December 31, 2014
(Decrease) increase Net pension Projected benefit
($ millions) benefit cost obligation (1)
Impact of increasing the rate of return assumption by 100 basis points (21 ) -
Impact of decreasing the rate of return assumption by 100 basis points 14 (33 )
Impact of increasing the discount rate assumption by 100 basis points (34 ) (347 )
Impact of decreasing the discount rate assumption by 100 basis points 41 431
(1) At the FortisBC Energy companies and FortisBC Electric, certain defined benefit pension plans have pension indexing provisions which provide for a portion of investment returns to be allocated in order to provide for indexing of pension benefits. Therefore, a change in the expected long-term rate of return on pension plan assets has an impact on the projected benefit obligation. The direction of the impact of a change in the rate of return assumption at the FortisBC Energy companies and FortisBC Electric is also the result of the methodology for determining the pension indexing assumption.

Other assumptions applied in measuring net benefit pension cost and/or the projected benefit obligation include the average rate of compensation increase, average remaining service life of the active employee group, and employee and retiree mortality rates.

As approved by the regulator, the cost of defined benefit pension plans at FortisAlberta is recovered in customer rates based on the cash payments made. Any difference between the cash payments made during the year and the cost incurred during the year is deferred as a regulatory asset or regulatory liability. Therefore, changes in assumptions result in changes in regulatory assets and regulatory liabilities for FortisAlberta. Central Hudson, the FortisBC Energy companies, FortisBC Electric and Newfoundland Power have regulator-approved mechanisms to defer variations in net pension cost from forecast net pension cost, used to set customer rates, as a regulatory asset or regulatory liability. There can be no assurance, however, that the above-noted deferral mechanisms will continue in the future as they are dependent on future regulatory decisions and orders.

As at December 31, 2014, for all defined benefit pension plans, the Corporation had consolidated projected benefit obligations of $2,604 million (December 31, 2013 - $1,724 million) and consolidated plan assets of $2,216 million (December 31, 2013 - $1,541 million), for a consolidated funded status in a liability position of $388 million (December 31, 2013 - $183 million). During 2014, the Corporation recognized consolidated net pension benefit cost of $71 million (2013 - $54 million).

OPEB Plans

The OPEB plans of the Corporation and its subsidiaries are also subject to judgments utilized in the actuarial determination of the cost and the accumulated benefit obligation. Similar assumptions as described above, except for the assumption of the expected long-term rate of return on pension plan assets, which is applicable only to the OPEB plans at UNS Energy and Central Hudson, along with the health care cost trend rate, were also utilized by management in determining net OPEB cost and accumulated benefit obligation.

The OPEB plan assets at UNS Energy and Central Hudson experienced total positive returns of approximately $11 million in 2014 compared to expected positive returns of approximately $9 million.

The following table provides the sensitivities associated with a 100 basis point change in the health care cost trend rate and the discount rate on 2014 net OPEB cost, and the related consolidated accumulated benefit obligation recognized in the Corporation's 2014 Audited Consolidated Financial Statements.

Sensitivity Analysis of Changes in Health Care Cost Trend Rate and Discount Rate
Year Ended December 31, 2014
Increase (decrease) Net OPEB Accumulated
($ millions) cost benefit obligation
Impact of increasing the health care cost trend rate assumption by 100 basis points 7 44
Impact of decreasing the health care cost trend rate assumption by 100 basis points (5 ) (34 )
Impact of increasing the discount rate assumption by 100 basis points (5 ) (74 )
Impact of decreasing the discount rate assumption by 100 basis points 7 91

Central Hudson, the FortisBC Energy companies, FortisBC Electric and Newfoundland Power have regulator-approved mechanisms to defer variations in net OPEB cost from forecast net OPEB cost, used to set customer rates, as a regulatory asset or regulatory liability. There can be no assurance, however, that the above-noted deferral mechanisms will continue in the future as they are dependent on future regulatory decisions and orders.

As at December 31, 2014, for all OPEB plans, the Corporation had consolidated accumulated benefit obligations of $564 million (December 31, 2013 - $417 million) and consolidated plan assets of $154 million (December 31, 2013 - $121 million), for a consolidated funded status in a liability position of $410 million (December 31, 2013 - $296 million). During 2014, the Corporation recognized consolidated net OPEB benefit cost of $21 million (2013 - $23 million).

AROs: The measurement of the fair value of AROs requires making reasonable estimates concerning the method of settlement and settlement dates associated with the legally obligated asset-retirement costs. There are also uncertainties in estimating future asset-retirement costs due to potential external events, such as changing legislation or regulations and advances in remediation technologies. While the Corporation has AROs associated with hydroelectric generating facilities, interconnection facilities, removal of certain distribution system assets from rights-of-way at the end of the life of the systems and the remediation of certain land, no amounts were recognized as at December 31, 2014 and 2013, with the exception of AROs recognized by UNS Energy, Central Hudson and FortisBC Electric.

The nature, amount and timing of costs associated with land and environmental remediation and/or removal of assets cannot be reasonably estimated at this time as the hydroelectric generation and T&D assets are reasonably expected to operate in perpetuity due to the nature of their operation; applicable licences, permits and interconnection facilities agreements are reasonably expected to be renewed or extended indefinitely to maintain the integrity of the related assets and ensure the continued provision of service to customers; a land-lease agreement is expected to be renewed indefinitely; and the exact nature and amount of land remediation is indeterminable. In the event that environmental issues are known and identified, assets are decommissioned or the applicable licences, permits, agreements or leases are terminated, AROs will be recognized at that time provided the costs can be reasonably estimated and are material.

As at December 31, 2014, UNS Energy recognized an approximate US$29 million ($34 million) ARO associated primarily with generation and photovoltaic assets; Central Hudson recognized an approximate US$1 million ($1 million) ARO (December 31, 2013 - US$1 million ($1 million)) associated primarily with asbestos remediation; and FortisBC Electric recognized an approximate $2 million ARO (December 31, 2013 - $2 million) associated with the removal of polychlorinated biphenyl ("PCB")-contaminated oil from electrical equipment. The total ARO liability as at December 31, 2014 has been classified on the consolidated balance sheet as a long-term other liability with the offset to utility capital assets. All factors used in estimating the companies' AROs represent management's best estimate of the fair value of the costs required to meet existing legislation or regulations. It is reasonably possible that volumes of contaminated assets, inflation assumptions, cost estimates to perform the work and the assumed pattern of annual cash flows may differ significantly from the companies' current assumptions. The AROs may change from period to period because of changes in the estimation of these uncertainties. Other subsidiaries also affected by AROs associated with the removal of PCB-contaminated oil from electrical equipment include Central Hudson, FortisAlberta, Newfoundland Power, FortisOntario and Maritime Electric. As at December 31, 2014, the AROs related to PCBs for the above-noted utilities were not material and, therefore, were not recognized.

Revenue Recognition: Revenue at the Corporation's regulated utilities is generally recognized on an accrual basis. Electricity and gas consumption is metered upon delivery to customers and is recognized as revenue using approved rates when consumed. Meters are read periodically and bills are issued to customers based on these readings. At the end of each reporting period, a certain amount of consumed electricity and gas will not have been billed. Electricity and gas that is consumed but not yet billed to customers is estimated and accrued as revenue at each period end, with the exception of certain electricity customers at Central Hudson, as approved by the regulator. As at December 31, 2014, approximately US$13 million ($15 million) (December 31, 2013 - US$13 million ($14 million)) in unbilled revenue at Central Hudson associated with these electricity customers was not accrued.

The unbilled revenue accrual for the period is based on estimated electricity and gas sales to customers for the period since the last meter reading at the rates approved by the respective regulatory authority. The development of the electricity and gas sales estimates generally requires analysis of consumption on a historical basis in relation to key inputs, such as the current price of electricity and gas, population growth, economic activity, weather conditions and system losses. The estimation process for accrued unbilled electricity and gas consumption will result in adjustments of electricity and gas revenue in the periods they become known, when actual results differ from the estimates. As at December 31, 2014, the amount of accrued unbilled revenue recognized in accounts receivable was approximately $365 million (December 31, 2013 - $341 million) on annual consolidated revenue of $5,401 million for 2014 (2013 - $4,047 million). The increase in accrued unbilled revenue of $24 million from December 31, 2013 was primarily due to the acquisition of UNS Energy, partially offset by lower distribution revenue at FortisAlberta.

Capitalized Overhead: As required by their respective regulator, UNS Energy, Central Hudson, the FortisBC Energy companies, FortisBC Electric, Newfoundland Power, Maritime Electric, Caribbean Utilities and Fortis Turks and Caicos capitalize overhead costs that are not directly attributable to specific utility capital assets but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized general overhead costs to utility capital assets is established by the respective regulator. Any change in the methodology of calculating and allocating general overhead costs to utility capital assets could have a material impact on the amount recognized as operating expenses versus utility capital assets.

As approved in the PBR decisions, effective January 1, 2014, the capitalized overhead rates at the FortisBC Energy companies and FortisBC Electric decreased from 14% to 12% and 20% to 15%, respectively, of gross regulated operating and maintenance costs. This resulted in an approximate $8 million decrease in utility capital assets during 2014 and a corresponding increase to operating expenses and revenue, as approved to be collected from customers.

Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position or results of operations.

The following describes the nature of the Corporation's contingencies.

UNS Energy

Springerville Unit 1

In November 2014 the Springerville Unit 1 third-party owners filed a complaint ("FERC Action") against TEP with FERC alleging that TEP had not agreed to wheel power and energy for the third-party owners in the manner specified in the Springerville Unit 1 facility support agreement between TEP and the third-party owners and for the cost specified by the third-party owners. The third-party owners requested an order from FERC requiring such wheeling of the third-party owners' energy from their Springerville Unit 1 interests beginning on January 1, 2015 for the price specified by the third-party owners. In December 2014 TEP filed a response to the FERC Action denying the allegations and requesting that FERC dismiss the complaint.

In December 2014 the third-party owners filed a complaint ("New York Action") against TEP in the Supreme Court of the State of New York, New York County, alleging, among other things, that: TEP has refused to comply with the third-party owners' instructions to schedule their entitlement share of power and energy; that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services; that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases; that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action; and that TEP has breached fiduciary duties claimed to be owed to the third-party owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial, and the third-party owners' fees and expenses.

In December 2014 Wilmington Trust Company, as owner trustees and lessors under the leases of the third-party owners, sent a notice to TEP that alleges that TEP has defaulted under the third-party owners' leases. The notice states that the owner trustees, as lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totalling approximately US$71 million. In a letter to Wilmington Trust Company in December 2014, TEP denied the allegations in the notice. In January 2015 Wilmington Trust Company sent a second notice to TEP that alleges that TEP has defaulted under the third-party owners' leases by not remediating the defaults alleged in the first notice. The second notice repeated the demand that TEP pay liquidated damages totalling approximately US$71 million. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.

TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time and, accordingly, no amount has been accrued in the consolidated financial statements. TEP intends to vigorously defend itself against the claims asserted by the third-party owners.

San Juan Generating Station

San Juan Coal Company ("SJCC") operates an underground coal mine in an area where certain gas producers have oil and gas leases with the Government of the United States, the State of New Mexico, and private parties. These gas producers allege that SJCC's underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan generating station, which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. The Company cannot reasonably estimate the impact of any future claims by these gas producers and, accordingly, no amount has been accrued in the consolidated financial statements.

Mine Reclamation Costs

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which the Company has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing the San Juan, Four Corners and Navajo generating stations. TEP's share of reclamation costs at all three mines is expected to be US$49 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The mine reclamation liability recorded as at December 31, 2014 was US$22 million and represents the present value of the estimated future liability.

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements' terms.

TEP is permitted to fully recover these costs from retail customers and, accordingly, these costs are deferred as a regulatory asset.

Central Hudson

Former MGP Facilities

Central Hudson and its predecessors owned and operated MGPs to serve their customers' heating and lighting needs. These plants manufactured gas from coal and oil beginning in the mid-to-late 1800s with all sites ceasing operations by the 1950s. This process produced certain by-products that may pose risks to human health and the environment.

The DEC, which regulates the timing and extent of remediation of MGP sites in New York State, has notified Central Hudson that it believes the Company or its predecessors at one time owned and/or operated MGPs at seven sites in Central Hudson's franchise territory. The DEC has further requested that the Company investigate and, if necessary, remediate these sites under a Consent Order, Voluntary Clean-up Agreement or Brownfield Clean-up Agreement. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated. As at December 31, 2014, an obligation of US$105 million was recognized in respect of MGP remediation and, based upon cost model analysis completed in 2012, it is estimated, with a 90% confidence level, that total costs to remediate these sites over the next 30 years will not exceed US$169 million.

Central Hudson has notified its insurers and intends to seek reimbursement from insurers for remediation, where coverage exists. Further, as authorized by the PSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for MGP site investigation and remediation and the associated rate allowances, with carrying charges to be accrued on the deferred balances at the authorized pre-tax rate of return.

Asbestos Litigation

Prior to and after the acquisition of CH Energy Group, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,348 asbestos cases have been raised, 1,170 remained pending as at December 31, 2014. Of the cases no longer pending against Central Hudson, 2,022 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 156 cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company's experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs which may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements.

FortisBC Electric

The Government of British Columbia filed a claim in the British Columbia Supreme Court ("B.C. Supreme Court") in June 2012 claiming on its behalf, and on behalf of approximately 17 homeowners, damages suffered as a result of a landslide caused by a dam failure in Oliver, British Columbia in 2010. The Government of British Columbia alleges in its claim that the dam failure was caused by the defendants', which include FortisBC Electric, use of a road on top of the dam. The Government of British Columbia estimates its damages and the damages of the homeowners, on whose behalf it is claiming, to be approximately $15 million. While FortisBC Electric has not been served, the Company has retained counsel and has notified its insurers. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

Fortis

Following the announcement of the acquisition of UNS Energy on December 11, 2013, four complaints which named Fortis and other defendants were filed in the Superior Court of the State of Arizona ("Superior Court") in and for the County of Pima and one claim in the United States District Court in and for the District of Arizona, challenging the acquisition. The complaints generally allege that the directors of UNS Energy breached their fiduciary duties in connection with the acquisition and that UNS Energy, Fortis, FortisUS Inc., and Color Acquisition Sub Inc. aided and abetted that breach. In March 2014 two of the four complaints filed in the Superior Court were dismissed by the plaintiffs and counsel for the parties in the two actions remaining in the Superior Court executed a Memorandum of Understanding recording an agreement-in-principle on the structure of a settlement to be proposed to the Superior Court for approval following closing of the acquisition. In April 2014 the complaint filed in the United States District Court was dismissed by the plaintiff. The outcome of these lawsuits cannot be predicted with any certainty and, accordingly, no amount has been accrued in the consolidated financial statements.

FHI

In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band ("Band"). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band's use and enjoyment of reserve lands. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

SELECTED ANNUAL FINANCIAL INFORMATION

The following table sets forth the annual financial information for the years ended December 31, 2014, 2013 and 2012.

Selected Annual Financial Information
Years Ended December 31
($ millions, except per share amounts) 2014 2013 2012
Revenue 5,401 4,047 3,654
Net earnings 390 420 371
Net earnings attributable to common equity shareholders 317 353 315
Basic earnings per common share 1.41 1.74 1.66
Diluted earnings per common share 1.40 1.73 1.65
Total assets 26,628 17,908 14,950
Long-term debt (including current portion) 10,501 7,204 5,900
Preference shares 1,820 1,229 1,108
Common shareholders' equity 6,871 4,772 3,992
Dividends declared per common share 1.30 1.25 1.21
Dividends declared per First Preference Share, Series C (1) - 0.4862 1.3625
Dividends declared per First Preference Share, Series E 1.2250 1.2250 1.2250
Dividends declared per First Preference Share, Series F 1.2250 1.2250 1.2250
Dividends declared per First Preference Share, Series G (2) 0.9708 1.1416 1.3125
Dividends declared per First Preference Share, Series H 1.0625 1.0625 1.0625
Dividends declared per First Preference Share, Series J (3) 1.1875 1.1875 0.3514
Dividends declared per First Preference Share, Series K (4) 1.0000 0.6233 -
Dividends declared per First Preference Share, Series M (5) 0.4613 - -
(1) In July 2013 the Corporation redeemed all of the issued and outstanding First Preference Shares, Series C at a redemption price of $25.1456 per share, being equal to $25.00 plus the amount of accrued and unpaid dividends per share.
(2) The annual fixed dividend per share for the First Preference Shares, Series G was reset from $1.3125 to $0.9708 for the five-year period from and including September 1, 2013 to but excluding September 1, 2018.
(3) The First Preference Shares, Series J were issued in November 2012 at $25.00 per share and are entitled to receive cumulative dividends in the amount of $1.1875 per share per annum.
(4) The Fixed Rate Reset First Preference Shares, Series K were issued in July 2013 at $25.00 per share and are entitled to receive cumulative dividends in the amount of $1.0000 per share per annum for the first six years.
(5) The Fixed Rate Reset First Preference Shares, Series M were issued in September 2014 at $25.00 per share and are entitled to receive cumulative dividends in the amount of $1.0250 per share per annum for the first five years.

2014/2013: Revenue increased $1,354 million, or 33.5%, from 2013 and net earnings attributable to common equity shareholders were $317 million, or $1.41 per common share, compared to $353 million, or $1.74 per common share, in 2013. For a discussion of the reasons for the changes in revenue, net earnings attributable to common equity shareholders, and earnings per common share, refer to the "Consolidated Results of Operations" and "Summary Financial Highlights" sections of this MD&A.

The growth in total assets reflects the Corporation's acquisition of UNS Energy in August 2014 and continued investment in energy infrastructure, driven by capital spending at the regulated utilities in western Canada and the continued construction of the Waneta Expansion. The increase in long-term debt was primarily due to the financing of the acquisition of UNS Energy, including debt assumed on acquisition, and in support of energy infrastructure investment.

2013/2012: Revenue increased $393 million, or 10.8%, from 2012. The increase was driven by the acquisition of Central Hudson, an increase in the base component of rates at most of the regulated utilities, higher electricity sales and gas volumes, and favourable foreign exchange associated with the translation of US dollar-denominated revenue. The increase was partially offset by decreases in the allowed ROEs at the FortisBC Energy companies and FortisBC Electric, and a decrease in the equity component of capital structure at FEI, effective January 1, 2013, as a result of the regulatory decision on the first stage of the GCOC Proceeding in British Columbia, lower net transmission revenue at FortisAlberta, and a decrease in the cost of natural gas charged to customers at the FortisBC Energy companies.

Net earnings attributable to common equity shareholders were $353 million, $38 million higher than 2012. Earnings for 2013 were reduced by $34 million as a result of expenses related to the Central Hudson acquisition, compared to $7.5 million of acquisition-related expenses for 2012. Earnings for 2013 were favourably impacted by an income tax recovery of $23 million, due to the enactment of higher deductions associated with Part VI.1 tax on the Corporation's preference share dividends, compared to income tax expenses of $4 million associated with Part VI.1 tax for 2012. In addition, an extraordinary gain of approximately $20 million was recognized in 2013 related to the settlement of expropriation matters associated with the Exploits Partnership. Excluding the above-noted items, net earnings attributable to common equity shareholders were $344 million for 2013, up $17.5 million from earnings of $326.5 million for 2012. Central Hudson contributed $23 million to earnings in 2013, while the non-regulated operations of CH Energy Group incurred a net loss of $5 million, largely associated with deferred income tax expenses related to the sale of Griffith.

Earnings at Canadian Regulated Gas and Electric Utilities were up $1 million from 2012. Earnings at the FortisBC Energy companies and FortisBC Electric were reduced by approximately $15 million and $4 million, respectively, as a result of a regulatory decision related to the first stage of the GCOC Proceeding, which reduced the ROE for each of the utilities and the equity component of capital structure for FEI, effective January 1, 2013. The decreases were partially offset by lower-than-expected finance charges and rate base growth, and lower operating and maintenance expenses at the FortisBC Energy companies. Earnings at FortisAlberta were $2 million lower than in 2012, as a result of lower net transmission revenue and costs related to flooding in southern Alberta in June 2013, partially offset by rate base growth and growth in the number of customers. Earnings at Newfoundland Power and Maritime Electric were favourably impacted by income tax recoveries associated with Part VI.1 tax. Newfoundland Power's earnings were also favourably impacted by rate base growth and a $1 million gain on the sale of land in 2013. Earnings at FortisOntario decreased due to the impact of the cumulative return adjustment on smart meter investments in 2012. Caribbean Regulated Electric Utilities delivered earnings $4 million higher than in 2012. The increase was primarily due to the regulator-approved capitalization of overhead costs at Fortis Turks and Caicos. Earnings at Non-Regulated Fortis Generation were up $22 million from 2012, driven by the extraordinary gain associated with the Exploits Partnership and increased hydroelectric production in Belize. Corporate and Other expenses were up $8 million from 2012. Higher acquisition-related expenses were partially offset by an income tax recovery associated with Part VI.1 tax, the release of income tax provisions and a foreign exchange gain in 2013, compared to a foreign exchange loss in 2012.

The growth in total assets reflects the Corporation's acquisition of Central Hudson in June 2013 and continued investment in energy infrastructure, driven by capital spending at the regulated utilities in western Canada and the continued construction of the Waneta Expansion. The increase in long-term debt was primarily due to the financing of the acquisition of Central Hudson, including debt assumed on acquisition, and in support of energy infrastructure investment.

Basic earnings per common share were $1.74 in 2013 compared to $1.66 in 2012. The increase was due to higher net earnings attributable to common equity shareholders, partially offset by the impact of a 6.6% increase in the weighted average number of common shares outstanding, largely due to the issuance of 18.5 million common shares pursuant to the conversion of Subscription Receipts on closing of the acquisition of Central Hudson in June 2013.

FOURTH QUARTER RESULTS

The following tables set forth unaudited financial information for the fourth quarters ended December 31, 2014 and 2013.

Summary of Gas Volumes and Energy and Electricity Sales
Fourth Quarters Ended December 31 (Unaudited) 2014 2013 Variance
Regulated Electric & Gas Utilities - United States
UNS Energy - Electricity Sales (GWh) 3,583 - 3,583
UNS Energy - Gas Volumes (PJ) 4 - 4
Central Hudson - Electricity Sales (GWh) 1,176 1,209 (33 )
Central Hudson - Gas Volumes (PJ) 5 5 -
Regulated Gas Utilities - Canadian
FortisBC Energy Companies (PJ) 59 68 (9 )
Regulated Electric Utilities - Canadian
FortisAlberta (GWh) 4,446 4,523 (77 )
FortisBC Electric (GWh) 846 887 (41 )
Eastern Canadian (GWh) 2,203 2,179 24
Regulated Electric Utilities - Caribbean (GWh) 187 189 (2 )
Non-Regulated - Fortis Generation (GWh) 109 144 (35 )

Gas Volumes

The decrease in gas volumes was mainly due to lower average consumption by residential, commercial and transportation customers at the FortisBC Energy companies due to warmer temperatures. The decrease was partially offset by gas volumes as a result of the acquisition of UNS Energy.

Energy and Electricity Sales

The increase in electricity sales was primarily due to the acquisition of UNS Energy and customer growth at the Eastern Canadian Regulated Electric Utilities. The increase was partially offset by lower average consumption by customers at FortisBC Electric and Central Hudson, reflecting warmer temperatures in the fourth quarter of 2014, and decreased non-regulated hydroelectric production in Belize due to lower rainfall. The decrease in energy deliveries at FortisAlberta was primarily due to lower average consumption by farm and irrigation customers, due to reduced heating load and reduced activity at the end of this year's irrigation season.

Segmented Revenue and Net Earnings Attributable to Common Equity Shareholders
Fourth Quarters Ended December 31 (Unaudited) Revenue Net Earnings
($ millions, except per share amounts) 2014 2013 Variance 2014 2013 Variance
Regulated Electric & Gas Utilities -
United States
UNS Energy 435 - 435 23 - 23
Central Hudson 186 165 21 4 11 (7 )
621 165 456 27 11 16
Regulated Gas Utilities - Canadian
FortisBC Energy Companies 432 446 (14 ) 49 50 (1 )
Regulated Electric Utilities - Canadian
FortisAlberta 132 121 11 25 18 7
FortisBC Electric 90 87 3 12 13 (1 )
Eastern Canadian Electric Utilities 266 261 5 14 14 -
488 469 19 51 45 6
Regulated Electric Utilities - Caribbean 84 77 7 6 8 (2 )
Non-Regulated - Fortis Generation 8 11 (3 ) 4 4 -
Non-Regulated - Non-Utility 62 62 - 7 3 4
Corporate and Other 7 7 - (31 ) (21 ) (10 )
Inter-Segment Eliminations (9 ) (8 ) (1 ) - - -
Total 1,693 1,229 464 113 100 13
Basic Earnings per Common Share ($) 0.44 0.47 (0.03 )

Revenue

The increase in revenue was driven by the acquisition of UNS Energy. An increase in the base component of rates at most of the regulated utilities, a higher commodity cost of natural gas charged to customers at the FortisBC Energy companies, and favourable foreign exchange associated with the translation of US dollar-denominated revenue also contributed to the increase in revenue. The increase was partially offset by lower electricity sales, lower gas volumes at the FortisBC Energy companies and lower non-regulated hydroelectric production in Belize.

Earnings

The increase in earnings was primarily due to: (i) earnings contribution of $23 million from UNS Energy; (ii) higher earnings at FortisAlberta, driven by customer growth and the timing of operating expenses; and (iii) higher earnings at the Non-Utility segment, due to higher contribution from Fortis Properties and the impact of a net loss of approximately $2.5 million at Griffith in the fourth quarter of 2013. The increase was partially offset by higher net Corporate and Other expenses and lower earnings at Central Hudson. The increase in net Corporate and Other expenses was primarily due to higher finance charges and preference share dividends associated with the financing of the acquisition of UNS Energy, and approximately $4 million in after-tax interest expense associated with the Convertible Debentures, partially offset by a higher income tax recovery. At Central Hudson, the continued impact of higher depreciation and operating expenses during the two-year rate freeze post acquisition had an unfavourable impact on earnings. Higher storm restoration and other non-recurring expenses also reduced earnings in the fourth quarter of 2014.

Summary of Consolidated Cash Flows
Fourth Quarters Ended December 31 (Unaudited)
($ millions) 2014 2013 Variance
Cash, Beginning of Period 458 155 303
Cash Provided by (Used in):
Operating Activities 334 233 101
Investing Activities (829 ) (344 ) (485 )
Financing Activities 257 31 226
Effect of Exchange Rate Changes on Cash and Cash Equivalents 10 - 10
Less Cash at Discontinued Operations - (3 ) 3
Cash, End of Period 230 72 158

Cash flow from operating activities was $101 million higher quarter over quarter. The increase was primarily due to the collection from customers of regulator-approved increases in depreciation and amortization and favourable changes in working capital, mainly at the FortisBC Energy companies and the Eastern Canadian Electric Utilities. The increase was partially offset by unfavorable changes in long-term regulatory deferrals.

Cash used in investing activities was $485 million higher quarter over quarter. The increase was mainly due to higher capital expenditures at the regulated utilities, driven by capital spending at UNS Energy, partially offset by lower capital expenditures at FortisAlberta and the non-regulated Waneta Expansion.

Cash provided by financing activities was $226 million higher quarter over quarter. The increase was primarily due to higher borrowings under committed credit facilities. The increase was partially offset by higher repayments of long-term debt and lower proceeds from long-term debt.

SUMMARY OF QUARTERLY RESULTS

The following table sets forth unaudited quarterly information for each of the eight quarters ended March 31, 2013 through December 31, 2014. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.

Summary of Quarterly Results Net Earnings
(Unaudited) Attributable to Earnings per Common
Common Equity Share
Revenue Shareholders Basic Diluted
Quarter Ended ($ millions) ($ millions) ($) ($)
December 31, 2014 1,693 113 0.44 0.43
September 30, 2014 1,197 14 0.06 0.06
June 30, 2014 1,056 47 0.22 0.22
March 31, 2014 1,455 143 0.67 0.66
December 31, 2013 1,229 100 0.47 0.47
September 30, 2013 915 48 0.23 0.23
June 30, 2013 790 54 0.28 0.28
March 31, 2013 1,113 151 0.79 0.76

The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions and associated acquisition-related expenses, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand and water flows, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel and purchased power and the cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters. Earnings for UNS Energy's electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

December 2014/December 2013: Net earnings attributable to common equity shareholders were $113 million, or $0.44 per common share, for the fourth quarter of 2014 compared to earnings of $100 million, or $0.47 per common share, for the fourth quarter of 2013. A discussion of the variances in financial results for the fourth quarter of 2014 and the fourth quarter of 2013 is provided in the "Fourth Quarter Results" section of this MD&A.

September 2014/September 2013: Net earnings attributable to common equity shareholders were $14 million, or $0.06 per common share, for the third quarter of 2014 compared to earnings of $48 million, or $0.23 per common share, for the third quarter of 2013. Earnings for the third quarter of 2014 were reduced by $35 million due to acquisition-related expenses and customer benefits offered to obtain regulatory approval of the acquisition of UNS Energy and $23 million in after-tax interest expense associated with the Convertible Debentures, including the make-whole payment. Earnings for the third quarter of 2013 reflected a net loss of approximately $2.5 million from discontinued operations associated with Griffith. Excluding the above-noted impacts of acquisition-related expenses, interest expense on the Convertible Debentures and Griffith, net earnings attributable to common equity shareholders for the third quarter of 2014 were $72 million compared to $51 million for the same period last year. The increase was driven by earnings contribution of $37 million at UNS Energy from the date of acquisition. The increase was partially offset by higher Corporate and Other expenses, primarily due to higher finance charges, largely due to the acquisition of UNS Energy, and higher operating expenses. The increase in operating expenses was mainly due to employee-related expenses, including approximately $8 million in after-tax retirement expenses recognized in the third quarter of 2014 and share-based compensation expenses as a result of share price appreciation, combined with higher legal and consulting fees and general inflationary increases. The increase in Corporate and Other expenses was partially offset by a $5 million foreign exchange gain in the third quarter of 2014, compared to a $2 million foreign exchange loss in the same quarter last year, a higher income tax recovery and interest income.

June 2014/June 2013: Net earnings attributable to common equity shareholders were $47 million, or $0.22 per common share, for the second quarter of 2014 compared to earnings of $54 million, or $0.28 per common share, for the second quarter of 2013. Earnings for the second quarter were reduced by $13 million in after-tax interest expense associated with the Convertible Debentures. Earnings for the second quarter of 2013 were reduced by $32 million, due to acquisition-related expenses and customer and community benefits offered to obtain regulatory approval of the acquisition of Central Hudson. Earnings for the second quarter of 2013 were favourably impacted by an income tax recovery of $25 million, due to the enactment of higher deductions associated with Part VI.1 tax on the Corporation's preference share dividends. Excluding the above-noted items, earnings for the second quarter of 2014 were consistent with the same period last year. Corporate and Other expenses were higher quarter over quarter due to unfavourable foreign exchange impacts, the impact of the release of income tax provisions in the second quarter of 2013, increased finance charges associated with the acquisition of Central Hudson and higher operating expenses, partially offset by a higher income tax recovery and interest income. The decrease in earnings was partially offset by: (i) earnings contribution from Central Hudson; (ii) the timing of the recognition of the regulatory decision on the first stage of the GCOC Proceeding in British Columbia at the FortisBC Energy companies and FortisBC Electric in 2013; (iii) electricity sales growth at the Caribbean Regulated Electric Utilities; and (iv) increased non-regulated hydroelectric generation in Belize.

March 2014/March 2013: Net earnings attributable to common equity shareholders were $143 million, or $0.67 per common share, for the first quarter of 2014 compared to earnings of $151 million, or $0.79 per common share, for the first quarter of 2013. Earnings for the first quarter of 2014 included $5 million from discontinued operations associated with Griffith and were reduced by $11 million in after-tax interest expense associated with the Convertible Debentures. Earnings for the first quarter of 2013 included an approximate $22 million extraordinary gain associated with the Exploits Partnership. Excluding the above-noted items, earnings for the first quarter of 2014 were favourably impacted by: (i) contribution of $18 million from Central Hudson; (ii) increased non-regulated hydroelectric generation in Belize; (iii) regulator-approved adjustments at Newfoundland Power, which impacted the timing of quarterly earnings; and (iv) electricity sales growth at the Caribbean Regulated Electric Utilities. The increases were partially offset by lower earnings at the FortisBC Energy companies and higher Corporate and Other expenses. The first stage of the GCOC Proceeding in British Columbia reduced the allowed ROE and common equity component of capital structure for the benchmark utility, FEI, effective January 1, 2013; however, the impact of this regulatory decision was not recognized until the second quarter of 2013, when the decision was received.

MANAGEMENT'S EVALUATON OF DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

Disclosure Controls and Procedures: The President and Chief Executive Officer ("CEO") and the Executive Vice President, Chief Financial Officer ("CFO") of Fortis, together with management, have established and maintain disclosure controls and procedures for the Corporation in order to provide reasonable assurance that material information relating to the Corporation is made known to them in a timely manner, particularly during the period in which the annual filings are being prepared. The CEO and CFO of Fortis, together with management, have evaluated the design and operating effectiveness of the Corporation's disclosure controls and procedures as of December 31, 2014 and, based on that evaluation, have concluded that these controls and procedures are effective in providing such reasonable assurance.

Internal Controls over Financial Reporting: The CEO and CFO of Fortis, together with management, are also responsible for establishing and maintaining internal controls over financial reporting ("ICFR") within the Corporation in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with US GAAP. The CEO and CFO of Fortis, together with management, have evaluated the design and operating effectiveness of the Corporation's ICFR as of December 31, 2014 and, based on that evaluation, have concluded that the controls are effective in providing such reasonable assurance. During the fourth quarter of 2014, there was no change in the Corporation's ICFR that has materially affected, or is reasonably likely to materially affect, the Corporation's ICFR.

OUTLOOK

Fortis is a leader in the North American electric and gas utility business, currently serving more than 3 million customers. The Corporation's focus continues to be on low-risk, regulated utility businesses and long-term contracted energy infrastructure.

In September 2014 the Corporation announced that it would engage in a review of strategic options for its hotel and commercial real estate business, operating as Fortis Properties. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering. A decision on this review is expected to be made in the second quarter of 2015. Fortis Properties currently comprises approximately 3% of the Corporation's total assets.

Following a decade of significant growth, mainly resulting from acquisitions, Fortis is entering a period of significant growth from its existing operations. The Corporation's consolidated capital program is expected to exceed $2.0 billion for 2015. Over the five-year period through 2019, it is expected to approach $9 billion.

Over the next five years, total investment in energy infrastructure is expected to increase midyear rate base by approximately 36% from $14 billion in 2014 to approximately $19 billion in 2019. This capital investment should allow rate base to increase at a five-year compound annual growth rate ("CAGR") of approximately 6.5% through 2019. Fortis expects that this investment will support continuing growth in earnings and dividends.

Fortis is also pursuing significant natural gas investment opportunities, particularly in British Columbia. Two new regulated projects - a further expansion of the Tilbury LNG facility and the Woodfibre pipeline expansion, could increase the five-year CAGR through 2019 to approximately 7.5%.

OUTSTANDING SHARE DATA

As at February 17, 2015, the Corporation had issued and outstanding 276.4 million common shares; 8.0 million First Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 10.0 million First Preference Shares, Series H; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared.

The number of common shares of Fortis that would be issued if all outstanding stock options and First Preference Shares, Series E were converted as at February 17, 2015 is as follows.

Conversion of Securities into Common Shares
As at February 17, 2015 (Unaudited) Number of
Common Shares
Security (millions)
Stock Options 4.4
First Preference Shares, Series E 5.4
Total 9.8

Additional information, including the Fortis 2014 Annual Information Form and Audited Consolidated Financial Statements, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.

FORTIS INC.

Consolidated Financial Statements

As at and for the years ended December 31, 2014 and 2013

Prepared in accordance with accounting principles generally accepted in the United States

Management's Report

The accompanying Annual Consolidated Financial Statements of Fortis Inc. have been prepared by management, who are responsible for the integrity of the information presented including the amounts that must, of necessity, be based on estimates and informed judgments. These Annual Consolidated Financial Statements were prepared in accordance with accounting principles generally accepted in the United States.

In meeting its responsibility for the reliability and integrity of the Annual Consolidated Financial Statements, management has developed and maintains a system of accounting and reporting which provides for the necessary internal controls to ensure transactions are properly authorized and recorded, assets are safeguarded and liabilities are recognized. The systems of the Corporation and its subsidiaries focus on the need for training of qualified and professional staff and the effective communication of management guidelines and policies. The effectiveness of the internal controls of Fortis Inc. is evaluated on an ongoing basis.

The Board of Directors oversees management's responsibilities for financial reporting through an Audit Committee which is composed entirely of outside independent directors. The Audit Committee oversees the external audit of the Corporation's Annual Consolidated Financial Statements and the accounting and financial reporting and disclosure processes and policies of the Corporation. The Audit Committee meets with management, the shareholders' auditors and the internal auditor to discuss the results of the external audit, the adequacy of the internal accounting controls and the quality and integrity of financial reporting. The Corporation's Annual Consolidated Financial Statements are reviewed by the Audit Committee with each of management and the shareholders' auditors before the statements are recommended to the Board of Directors for approval. The shareholders' auditors have full and free access to the Audit Committee. The Audit Committee has the duty to review the adoption of, and changes in, accounting principles and practices which have a material effect on the Corporation's Annual Consolidated Financial Statements and to review and report to the Board of Directors on policies relating to the accounting and financial reporting and disclosure processes.

The Audit Committee has the duty to review financial reports requiring Board of Directors' approval prior to the submission to securities commissions or other regulatory authorities, to assess and review management judgments material to reported financial information and to review shareholders' auditors' independence and auditors' fees. The 2014 Annual Consolidated Financial Statements were reviewed by the Audit Committee and, on their recommendation, were approved by the Board of Directors of Fortis Inc. Ernst & Young LLP, independent auditors appointed by the shareholders of Fortis Inc. upon recommendation of the Audit Committee, have performed an audit of the 2014 Annual Consolidated Financial Statements and their report follows.

Barry V. Perry

President and Chief Executive Officer, Fortis Inc.

Karl W. Smith

Executive Vice President, Chief Financial Officer, Fortis Inc.

St. John's, Canada

Independent Auditors' Report

To the Shareholders of Fortis Inc.

We have audited the accompanying consolidated financial statements of Fortis Inc., which comprise the consolidated balance sheets as at December 31, 2014 and 2013, and the consolidated statements of earnings, comprehensive income, cash flows and changes in equity for the years then ended, and a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Fortis Inc. as at December 31, 2014 and 2013 and its financial performance and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States.

St. John's, Canada

February 18, 2015

Ernst & Young LLP

Chartered Professional Accountants

Fortis Inc.
Consolidated Balance Sheets
As at December 31
(in millions of Canadian dollars)
20142013
ASSETS
Current assets
Cash and cash equivalents$230$72
Accounts receivable and other current assets (Note 5) 900 732
Prepaid expenses 59 45
Inventories (Note 6) 321 143
Regulatory assets (Note 7) 295 150
Assets held for sale (Note 26) - 112
Deferred income taxes (Note 25) 158 42
1,963 1,296
Other assets (Note 8) 337 246
Regulatory assets (Note 7) 2,230 1,672
Deferred income taxes (Note 25) 62 7
Utility capital assets (Note 9) 17,152 11,618
Non-utility capital assets (Note 10) 664 649
Intangible assets (Note 11) 488 345
Goodwill (Note 12) 3,732 2,075
$26,628$17,908
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 33)$330$160
Accounts payable and other current liabilities (Note 13) 1,440 957
Regulatory liabilities (Note 7) 192 140
Current installments of long-term debt (Note 14) 505 780
Current installments of capital lease and finance obligations (Note 15) 208 7
Liabilities associated with assets held for sale (Note 26) - 32
Deferred income taxes (Note 25) 9 8
2,684 2,084
Other liabilities (Note 16) 1,141 627
Regulatory liabilities (Note 7) 1,363 902
Deferred income taxes (Note 25) 1,837 1,078
Long-term debt (Note 14) 9,996 6,424
Capital lease and finance obligations (Note 15) 495 417
17,516 11,532
Shareholders' equity
Common shares (1) (Note 17) 5,667 3,783
Preference shares (Note 19) 1,820 1,229
Additional paid-in capital 15 17
Accumulated other comprehensive income (loss) (Note 20) 129 (72)
Retained earnings 1,060 1,044
8,691 6,001
Non-controlling interests (Note 21) 421 375
9,112 6,376
$26,628$17,908
(1)No par value. Unlimited authorized shares; 276.0 million and 213.2 million issued and outstanding as at December 31, 2014 and 2013, respectivelyApproved on Behalf of the Board
Commitments (Note 34)
Contingencies (Note 36) David G. Norris, Peter E. Case,
See accompanying Notes to Consolidated Financial StatementsDirectorDirector
Fortis Inc.
Consolidated Statements of Earnings
For the years ended December 31
(in millions of Canadian dollars, except per share amounts)
2014 2013
Revenue$5,401 $4,047
Expenses
Energy supply costs 2,197 1,617
Operating 1,493 1,037
Depreciation and amortization 688 541
4,378 3,195
Operating income 1,023 852
Other income (expenses), net (Note 23) (25) (31)
Finance charges (Note 24) 547 389
Earnings before income taxes, discontinued operations and extraordinary item 451 432
Income tax expense (Note 25) 66 32
Earnings from continuing operations 385 400
Earnings from discontinued operations, net of tax (Note 26) 5 -
Earnings before extraordinary item 390 400
Extraordinary gain, net of tax (Note 27) - 20
Net earnings$390 $420
Net earnings attributable to:
Non-controlling interests$11 $10
Preference equity shareholders 62 57
Common equity shareholders 317 353
$390 $420
Earnings per common share from continuing operations (Note 18)
Basic$1.39 $1.64
Diluted$1.38 $1.63
Earnings per common share (Note 18)
Basic$1.41 $1.74
Diluted$1.40 $1.73
See accompanying Notes to Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income
For the years ended December 31
(in millions of Canadian dollars)
2014 2013
Net earnings$390 $420
Other comprehensive income (loss)
Unrealized foreign currency translation gains, net of hedging activities and tax (Note 20) 204 16
Net change in fair value of cash flow hedges, net of tax (Notes 20 and 32) 1 -
Reclassification to earnings of net losses on derivative instruments discontinued as cash flow hedges, net of tax (Note 20) 1 1
Unrealized employee future benefits (losses) gains, net of tax (Notes 20 and 28) (5) 7
201 24
Comprehensive income$591 $444
Comprehensive income attributable to:
Non-controlling interests$11 $10
Preference equity shareholders 62 57
Common equity shareholders 518 377
$591 $444
See accompanying Notes to Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows
For the years ended December 31
(in millions of Canadian dollars)
2014 2013
Operating activities
Net earnings$390 $420
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation - capital assets 597 475
Amortization - intangible assets 60 49
Amortization - other 31 17
Deferred income tax expense (recovery) (Note 25) 23 (6)
Accrued employee future benefits 25 17
Equity component of allowance for funds used during construction (Note 23) (11) (8)
Other 71 (34)
Change in long-term regulatory assets and liabilities (80) 14
Change in non-cash operating working capital (Note 31) (124) (45)
982 899
Investing activities
Change in other assets and other liabilities (4) (8)
Capital expenditures - utility capital assets (1,617) (1,089)
Capital expenditures - non-utility capital assets (39) (46)
Capital expenditures - intangible assets (69) (40)
Contributions in aid of construction 69 54
Proceeds on disposal and settlement of assets (Notes 26 and 27) 109 20
Business acquisitions, net of cash acquired (Note 29) (2,648) (1,055)
(4,199) (2,164)
Financing activities
Change in short-term borrowings 167 (6)
Proceeds from convertible debentures, net of issue costs (Note 17) 1,725 -
Proceeds from long-term debt, net of issue costs 1,193 653
Repayments of long-term debt and capital lease and finance obligations (743) (173)
Net borrowings under committed credit facilities 610 184
Advances from non-controlling interests 38 63
Issue of common shares, net of costs and dividends reinvested (Note 17) 51 596
Issue of preference shares, net of costs (Note 19) 586 242
Redemption of preference shares (Note 19) - (125)
Dividends
Common shares, net of dividends reinvested (194) (181)
Preference shares (62) (56)
Subsidiary dividends paid to non-controlling interests (10) (11)
3,361 1,186
Effect of exchange rate changes on cash and cash equivalents 14 -
Change in cash and cash equivalents 158 (79)
Less cash at discontinued operations (Note 26) - (3)
Cash and cash equivalents, beginning of year 72 154
Cash and cash equivalents, end of year$230 $72
Supplementary Information to Consolidated Statements of Cash Flows (Note 31)
See accompanying Notes to Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2014 and 2013
(in millions of Canadian dollars)
Accumulated
Additional Other Non-
Common Preference Paid-in Comprehensive Retained Controlling Total
Shares Shares Capital (Loss) Income Earnings Interests Equity
(Note 17) (Note 19) (Note 20) (Note 21)
As at January 1, 2014$3,783 $1,229 $17 $(72)$1,044 $375 $6,376
Net earnings - - - - 379 11 390
Other comprehensive income - - - 201 - - 201
Preference share issue - 591 - - - - 591
Common share issues 1,884 - (5) - - - 1,879
Stock-based compensation - - 3 - - - 3
Advances from non-controlling interests - - - - - 38 38
Foreign currency translation impacts - - - - - 7 7
Subsidiary dividends paid to non-controlling interests - - - - - (10) (10)
Dividends declared on common shares ($1.30 per share) - - - - (301) - (301)
Dividends declared on preference shares - - - - (62) - (62)
As at December 31, 2014$5,667 $1,820 $15 $129 $1,060 $421 $9,112
As at January 1, 2013$3,121 $1,108 $15 $(96)$952 $310 $5,410
Net earnings - - - - 410 10 420
Other comprehensive income - - - 24 - - 24
Preference share issue - 244 - - - - 244
Preference share redemption - (123) - - - - (123)
Common share issues 662 - (1) - - - 661
Stock-based compensation - - 3 - - - 3
Advances from non-controlling interests - - - - - 63 63
Foreign currency translation impacts - - - - - 3 3
Subsidiary dividends paid to non-controlling interests - - - - - (11) (11)
Dividends declared on common shares ($1.25 per share) - - - - (261) - (261)
Dividends declared on preference shares - - - - (57) - (57)
As at December 31, 2013$3,783 $1,229 $17 $(72)$1,044 $375 $6,376
See accompanying Notes to Consolidated Financial Statements
FORTIS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2014 and 2013

1. DESCRIPTION OF THE BUSINESS

Nature of Operations

Fortis Inc. ("Fortis" or the "Corporation") is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated generation and non-utility assets, which are treated as two separate segments. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.

The following summary describes the operations included in each of the Corporation's reportable segments.

REGULATED UTILITIES

The Corporation's interests in regulated electric and gas utilities are as follows.

Regulated Electric & Gas Utilities - United States

a. UNS Energy: Primarily comprised of Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"), (collectively, the "UNS Utilities"), acquired by Fortis in August 2014 (Note 29).

TEP, UNS Energy's largest operating subsidiary, is a vertically integrated regulated electric utility. TEP generates, transmits and distributes electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells wholesale electricity to other entities in the western United States.

UNS Electric is a vertically integrated regulated electric utility, which generates, transmits and distributes electricity to retail customers in Arizona's Mohave and Santa Cruz counties.

TEP and UNS Electric currently own or lease generation resources with an aggregate capacity of 2,746 megawatts ("MW"), including 53 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at January 1, 2015, approximately 48% of the generating capacity is fuelled by coal.

UNS Gas is a regulated gas distribution company. The Company serves retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.

b. Central Hudson: Central Hudson Gas & Electric Corporation ("Central Hudson") is a regulated transmission and distribution ("T&D") utility, serving eight counties of New York State's Mid-Hudson River Valley. The Company owns minimal gas-fired and hydroelectric generating capacity totalling 64 MW. Central Hudson was acquired by Fortis in June 2013 (Note 29).

Regulated Gas Utilities - Canadian

FortisBC Energy Companies: Primarily includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"), (collectively, the "FortisBC Energy companies"). On December 31, 2014, FEI, FEVI and FEWI were amalgamated and FEI is the resulting Company.

FEI is the largest distributor of natural gas in British Columbia, serving more than 125 communities. Major areas served by the Company are the Lower Mainland, Vancouver Island, Sunshine Coast, Whistler and Interior of British Columbia.

FEI provides T&D services to customers, and obtains natural gas supplies on behalf of most residential, commercial and industrial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through FEI's Southern Crossing pipeline, from Alberta.

Regulated Electric Utilities - Canadian

a. FortisAlberta: FortisAlberta Inc. ("FortisAlberta") owns and operates the electricity distribution system in a substantial portion of southern and central Alberta. The Company does not own or operate generation or transmission assets and is not involved in the direct sale of electricity.

b. FortisBC Electric: Includes FortisBC Inc., an integrated electric utility operating in the southern interior of British Columbia. FortisBC Inc. owns four hydroelectric generating facilities with a combined capacity of 225 MW. Also included in the FortisBC Electric segment are the operating, maintenance and management services relating to the 493-MW Waneta hydroelectric generating facility owned by Teck Metals Ltd. and BC Hydro, the 149-MW Brilliant hydroelectric plant ("Brilliant Plant") and the 120-MW Brilliant hydroelectric expansion plant, both owned by Columbia Power Corporation and Columbia Basin Trust ("CPC/CBT"), and the 185-MW Arrow Lakes hydroelectric plant owned by CPC/CBT. In March 2013 FortisBC Inc. acquired the City of Kelowna's electric utility assets (Note 29).

c. Eastern Canadian: Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited ("Maritime Electric") and FortisOntario Inc. ("FortisOntario"). Newfoundland Power is an integrated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador. Newfoundland Power has an installed generating capacity of 139 MW, of which 97 MW is hydroelectric generation. Maritime Electric is an integrated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI"). Maritime Electric also maintains on-Island generating facilities with a combined capacity of 150 MW. FortisOntario provides integrated electric utility service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. FortisOntario's operations are primarily comprised of Canadian Niagara Power Inc. ("Canadian Niagara Power"), Cornwall Street Railway, Light and Power Company, Limited ("Cornwall Electric") and Algoma Power Inc. ("Algoma Power").

Regulated Electric Utilities - Caribbean

The Regulated Electric Utilities - Caribbean segment includes Caribbean Utilities Company, Ltd. ("Caribbean Utilities") and Fortis Turks and Caicos. Caribbean Utilities is an integrated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands. The Company has an installed diesel-powered generating capacity of 132 MW. Fortis holds an approximate 60% controlling ownership interest in Caribbean Utilities (December 31, 2013 - 60%). Caribbean Utilities is a public company traded on the Toronto Stock Exchange ("TSX") (TSX:CUP.U). Fortis Turks and Caicos is comprised of two integrated electric utilities that provide electricity to certain islands in Turks and Caicos. The utilities have a combined diesel-powered generating capacity of 76 MW.

NON-REGULATED - FORTIS GENERATION

Fortis Generation includes the financial results of non-regulated generation assets in Belize, British Columbia, Upstate New York and Ontario.

Generating assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW. All of the output of these facilities is sold to Belize Electricity Limited ("Belize Electricity") under 50-year power purchase agreements ("PPAs") expiring in 2055 and 2060. The hydroelectric generation operations in Belize are conducted through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL") under a franchise agreement with the Government of Belize ("GOB").

In British Columbia, generating assets include the 16-MW run-of-river Walden hydroelectric generating facility ("Walden") and the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion"). All of the output of Walden is sold to BC Hydro under a long-term contract that cannot be terminated prior to 2024. Construction of the Waneta Expansion, which is adjacent to the Waneta Dam and powerhouse facilities on the Pend d'Oreille River, south of Trail, British Columbia, commenced late in 2010 and the facility is expected to come into service in spring 2015. The output of the Waneta Expansion will be sold to BC Hydro and FortisBC Electric under 40-year contracts. The Corporation's 51% controlling ownership interest in the Waneta Expansion is conducted through the Waneta Expansion Limited Partnership ("Waneta Partnership"), with CPC/CBT holding the remaining 49% interest.

Generating assets in Upstate New York are comprised of four hydroelectric generating facilities with a combined capacity of approximately 23 MW, operating under licences from the U.S. Federal Energy Regulatory Commission ("FERC"). Hydroelectric generation operations in Upstate New York are conducted through the Corporation's indirectly wholly owned subsidiary FortisUS Energy Corporation ("FortisUS Energy").

In Ontario, generating assets include six small hydroelectric generating facilities with a combined capacity of 8 MW and a 5-MW gas-powered cogeneration plant in Cornwall.

NON-REGULATED - NON-UTILITY

The Non-Utility segment includes Fortis Properties Corporation ("Fortis Properties") and, from June 2013 through March 2014, Griffith Energy Services, Inc. ("Griffith"). Fortis Properties owns and operates 23 hotels, comprised of more than 4,400 rooms, in eight Canadian provinces, and owns and operates approximately 2.8 million square feet of commercial office and retail space, primarily in Atlantic Canada. In September 2014 the Corporation announced that it would engage in a review of strategic options for its hotel and commercial real estate business. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering.

Griffith was acquired by Fortis as part of the acquisition of Central Hudson in June 2013 and was sold in March 2014 (Notes 26 and 29).

CORPORATE AND OTHER

The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments.

The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group, Inc. ("CH Energy Group") and UNS Energy Corporation. Net Corporate expenses include finance charges; dividends on preference shares; other corporate expenses, including corporate operating costs, net of recoveries from subsidiaries; acquisition-related expenses; interest and miscellaneous revenue; and related income taxes.

Also included in the Corporate and Other segment are the financial results of FortisBC Alternative Energy Services Inc. ("FAES"). FAES is a wholly owned subsidiary of FHI that provides alternative energy solutions, including thermal-energy and geo-exchange systems.

2. NATURE OF REGULATION

The Corporation's regulated utilities are primarily determined under cost of service ("COS") regulation and, in certain circumstances, performance-based rate-setting ("PBR") mechanisms. Generally, under COS regulation the respective regulatory authority sets customer electricity and/or gas rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") depends on the utility achieving the forecasts established in the rate-setting processes. When PBR mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudent COS and earn its allowed ROE.

When future test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. In addition, the Corporation's regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms (Note 7).

The nature of regulation at the Corporation's utilities is as follows.

UNS Energy

The UNS Utilities are regulated by the Arizona Corporation Commission ("ACC") regarding such matters as retail electric and gas rates, construction, operations, financing, accounting, transactions with affiliated parties and issuance of securities. Certain activities of the utilities are subject to regulation by FERC under the Federal Power Act (United States), including such matters as the terms and prices of transmission services and wholesale electricity sales.

The UNS Utilities operate under COS regulation as administered by the ACC. The ACC provides for the use of a historical test year in the establishment of retail electric and gas rates for the utilities. Retail electric and gas rates are set to provide the utilities with an opportunity to recover their costs of service and earn a reasonable rate of return on rate base, including an adjustment for the fair value of rate base as required under the laws of the State of Arizona.

TEP's allowed ROE is set at 10.0% on a capital structure of 43.5% common equity, effective from July 1, 2013. UNS Electric's allowed ROE is set at 9.50% on a capital structure of 52.6% common equity, effective from January 1, 2014. UNS Gas' allowed ROE is set at 9.75% on a capital structure of 50.8% common equity, effective from May 1, 2012.

Central Hudson

Central Hudson is regulated by the New York State Public Service Commission ("PSC") regarding such matters as rates, construction, operations, financing, accounting and issuance of securities. Certain activities of the Company are subject to regulation by FERC under the Federal Power Act (United States). Central Hudson is also subject to regulation by the North American Electric Reliability Corporation.

Central Hudson operates under COS regulation as administered by the PSC with the use of a future test year in the establishment of rates for the utility.

Central Hudson's allowed ROE is set at 10.0% on a deemed capital structure of 48% common equity. The Company began operating under a three-year rate order issued by the PSC effective July 1, 2010. As approved by the PSC in June 2013, the original three-year rate order was extended for two years, through June 30, 2015, as a condition required to close the acquisition (Note 29). Effective July 1, 2013, Central Hudson is also subject to an earnings sharing mechanism, whereby the Company and customers share equally earnings in excess of the allowed ROE up to an achieved ROE that is 50 basis points above the allowed ROE, and share 10%/90% (Company/customers) earnings in excess of 50 basis points above the allowed ROE.

FortisBC Energy Companies and FortisBC Electric

The FortisBC Energy companies and FortisBC Electric are regulated by the British Columbia Utilities Commission ("BCUC"). The BCUC administers acts and regulations pursuant to the Utilities Commission Act (British Columbia), covering such matters as tariffs, rates, construction, operations, financing and accounting. FEI, FEVI, FEWI and FortisBC Electric primarily operate under COS regulation and, from time to time, PBR mechanisms for establishing customer rates.

In 2013 the BCUC issued its decision on the first stage of the Generic Cost of Capital ("GCOC") Proceeding in British Columbia. Effective January 1, 2013, the decision set the allowed ROE of the benchmark utility, FEI, at 8.75% with a 38.5% common equity component of capital structure. The common equity component of capital structure will remain in effect until December 31, 2015. Effective January 1, 2014 through December 31, 2015, the BCUC has also introduced an Automatic Adjustment Mechanism ("AAM") to set the allowed ROE for the benchmark utility on an annual basis. The AAM will take effect when the long-term Government of Canada bond yield exceeds 3.8%. In January 2014 the BCUC confirmed that the necessary conditions for the AAM to be triggered for the 2014 allowed ROE have not been met; therefore, the benchmark allowed ROE remained at 8.75% for 2014. FEVI, FEWI and FortisBC Electric's allowed ROEs and common equity component of capital structures were determined in the second stage of the GCOC Proceeding. However, as a result of the decision on the first stage of the GCOC Proceeding, which reduced the allowed ROE of the benchmark utility by 75 basis points, the interim allowed ROEs for FEVI, FEWI and FortisBC Electric decreased to 9.25%, 9.25% and 9.15%, respectively, effective January 1, 2013, while the deemed common equity component of capital structures remained unchanged.

In March 2014 the BCUC issued its decision on the second stage of the GCOC Proceeding. Effective January 1, 2013, the decision set the common equity component of capital structure for FEVI and FEWI at 41.5%, and reaffirmed the common equity component of capital structure for FortisBC Electric at 40%. The BCUC reaffirmed for FEVI and FortisBC Electric a risk premium over the benchmark utility of 50 basis points and 40 basis points, respectively, and set FEWI's equity risk premium at 75 basis points, which represented an increase of 25 basis points. The resulting allowed ROEs, effective January 1, 2013, for FEVI, FEWI and FortisBC Electric are 9.25%, 9.50% and 9.15%, respectively. The cumulative impact of the outcome of the second stage of the GCOC Proceeding was recognized in 2014 and did not have a material impact on earnings.

In September 2014 the BCUC issued its decisions on FEI's and FortisBC Electric's Multi-Year PBR Plans for 2014 through 2018. As part of the PBR decisions, the terms were extended to 2019. The approved PBR Plans incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FEI and 1.03% for FortisBC Electric each year. The approved PBR Plans also include a 50%/50% sharing of variances from the formula-driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FEI and FortisBC Electric maintain service levels. It also sets out the requirements for an annual review process which will provide a forum for discussion between the utilities and interested parties regarding current performance and future activities.

FortisAlberta

FortisAlberta is regulated by the Alberta Utilities Commission ("AUC") pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Hydro and Electric Energy Act (Alberta) and the Alberta Utilities Commission Act (Alberta). The AUC administers these acts and regulations, covering such matters as tariffs, rates, construction, operations and financing.

Effective January 1, 2013, the AUC prescribed that distribution utilities in Alberta, including FortisAlberta, move to PBR for a five-year term. Under PBR, each year this formula is applied to the preceding year's distribution rates and for 2013 and 2014 the formula was applied to the 2012 distribution rates. For 2013 and 2014, an allowed ROE of 8.75% was established by the AUC on an interim basis on a deemed capital structure of 41% common equity, pending the outcome of a GCOC Proceeding in Alberta.

The PBR plan includes mechanisms for the recovery or settlement of items determined to flow through directly to customers ("Y factor") and the recovery of costs related to capital expenditures that are not being recovered through the inflationary factor of the formula ("K factor" or "capital tracker"). The AUC also approved a Z factor, a PBR re-opener and an ROE efficiency carry-over mechanism. The Z factor permits an application for recovery of costs related to significant unforeseen events. The PBR re-opener permits an application to re-open and review the PBR plan to address specific problems with the design or operation of the PBR plan. The use of the Z factor and PBR re-opener mechanisms is associated with certain thresholds. The ROE efficiency carry-over mechanism provides an efficiency incentive by permitting a utility to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of that term.

A hearing related to the GCOC Proceeding in Alberta concluded in June 2014, with supplemental submissions filed in November 2014. As a result of this proceeding, the AUC is expected to set the allowed ROE and capital structure for utilities in Alberta for 2013, 2014 and possibly 2015. The AUC will also consider re-establishing a formula-based approach to setting the allowed ROE going forward. A decision on this proceeding is expected from the AUC in the first quarter of 2015.

A hearing related to the combined capital tracker application for 2013 and 2014 was held in October 2014 with an AUC decision expected during the first quarter of 2015. FortisAlberta's 2013 and 2014 capital tracker revenue was based on a placeholder equal to 60% of the then applied for capital tracker amounts. Any adjustment to the 60% capital tracker placeholder for 2013 and 2014 will result in an adjustment to revenue. Such an adjustment would be recognized in the consolidated financial statements when the regulatory decision is received, or when sufficient information is available to reasonably estimate the required adjustment in accordance with US GAAP.

Eastern Canadian Electric Utilities

Newfoundland Power operates under COS regulation and is regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") under the Public Utilities Act (Newfoundland and Labrador). The Public Utilities Act (Newfoundland and Labrador) provides for the PUB's general supervision of the Company's utility operations and requires the PUB to approve, among other things, customer rates, capital expenditures and the issuance of securities of Newfoundland Power. Newfoundland Power uses a future test year in the establishment of rates. The PUB has set the allowed ROE at 8.8% and the common equity component of capital structure at 45% for 2013 and 2014.

Maritime Electric operates under COS regulation as prescribed by the Island Regulatory and Appeals Commission ("IRAC") under the provisions of the Electric Power Act (PEI), the Renewable Energy Act (PEI), the Electric Power (Electricity Rate-Reduction) Amendment Act (PEI), which covers the period March 1, 2011 to February 28, 2013, and the Electric Power (Energy Accord Continuation) Amendment Act (PEI) ("Accord Continuation Act"), which covers the period March 1, 2013 to February 29, 2016. IRAC uses a future test year for the establishment of rates for the utility. Maritime Electric's allowed ROE was set at 9.75% on a targeted minimum capital structure of 40% common equity for 2013 and 2014.

At FortisOntario, Canadian Niagara Power, Algoma Power and Cornwall Electric operate under the Electricity Act (Ontario) and the Ontario Energy Board Act (Ontario), as administered by the Ontario Energy Board ("OEB"). Canadian Niagara Power and Algoma Power operate under COS regulation and earnings are regulated on the basis of rate of return on rate base, plus a recovery of allowable distribution costs. In non-rebasing years, customer electricity distribution rates are set using inflationary factors less an efficiency target under the Fourth-Generation Incentive Regulation Mechanism as prescribed by the OEB. Algoma Power is also subject to the use and implementation of the Rural and Remote Rate Protection ("RRRP") Program. The RRRP Program is calculated as the deficiency between the approved revenue requirement from the OEB and current customer electricity distribution rates, adjusted for the average rate increase across the province of Ontario. Canadian Niagara Power and Algoma Power use a future test year in the establishment of rates. Canadian Niagara Power's allowed ROE was set at 8.93% on a deemed capital structure of 40% common equity for 2013 and 2014. Algoma Power's allowed ROE was set at 9.85% on a deemed capital structure of 40% common equity for 2013 and 2014.

Cornwall Electric is subject to a rate-setting mechanism under a 35-year Franchise Agreement with the City of Cornwall expiring in 2033 and, therefore, is exempt from many aspects of the above Acts. The rate-setting mechanism is based on a price cap with commodity cost flow through. The base revenue requirement is adjusted annually for inflation, load growth, customer growth and premises vacancies.

Regulated Electric Utilities - Caribbean

Caribbean Utilities operates under T&D and generation licences from the Government of the Cayman Islands. The exclusive T&D licence is for an initial period of 20 years, expiring April 2028, with a provision for automatic renewal. As a result of a successful generation bid for new generation capacity, in November 2014 a new non-exclusive generation licence was issued for a term of 25 years, expiring in November 2039. The licences detail the role of the Electricity Regulatory Authority, which oversees all licences, establishes and enforces licence standards, reviews the rate-cap adjustment mechanism ("RCAM"), and annually approves capital expenditures. The licences contain the provision for an RCAM based on published consumer price indices. Caribbean Utilities' targeted allowed ROA for 2014 was in the range of 7.00% to 9.00%, as compared to a range of 6.50% to 8.50% for 2013.

Fortis Turks and Caicos operates under two 50-year licences expiring in 2037 and 2036. Among other matters, the licences describe how electricity rates are set by the Government of the Turks and Caicos Islands, using a historical test year, in order to provide the utilities with an allowed ROA of between 15.0% and 17.50% (the "Allowable Operating Profit"), based on a calculated rate base and including interest on the amounts by which actual operating profits fall short of the Allowable Operating Profits on a cumulative basis (the "Cumulative Shortfall"). Annual submissions are made to the Government of the Turks and Caicos Islands calculating the amount of the Allowable Operating Profit and the Cumulative Shortfall. The submissions for 2014 calculated the Allowable Operating Profit for 2014 to be $42 million (US$38 million) and the Cumulative Shortfall as at December 31, 2014 to be $190 million (US$164 million). The recovery of the Cumulative Shortfall is, however, dependent on future sales volumes and expenses. The achieved ROAs at the utilities have been significantly lower than those allowed under the licences as a result of the inability, due to economic and political factors, to increase base electricity rates associated with significant capital investment in recent years.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP"), which for regulated utilities include specific accounting guidance for regulated operations, as outlined in Note 2 and the following summary of significant accounting policies.

All amounts presented are in Canadian dollars unless otherwise stated.

Basis of Presentation

The consolidated financial statements reflect the Corporation's investments in its subsidiaries on a consolidated basis, with the equity method used for entities in which Fortis has significant influence, but not control, and proportionate consolidation for generation and transmission assets that are jointly owned with non-affiliated entities. All material intercompany transactions have been eliminated in the consolidated financial statements.

An evaluation of subsequent events through to February 18, 2015, the date these consolidated financial statements were approved by the Board of Directors of Fortis ("Board of Directors"), was completed to determine whether the circumstances warranted recognition and disclosure of events or transactions in the consolidated financial statements as at December 31, 2014.

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term deposits with initial maturities of three months or less from the date of deposit.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects management's best estimate of uncollectible accounts receivable balances. Fortis and each of its subsidiaries maintain an allowance for doubtful accounts that is estimated based on a variety of factors including accounts receivable aging, historical experience and other currently available information, including events such as customer bankruptcy and economic conditions. Interest is charged on accounts receivable balances that have been outstanding for more than 21 to 30 days. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible.

Regulatory Assets and Liabilities

Regulatory assets and liabilities arise as a result of the rate-setting process at the Corporation's regulated utilities. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process.

All amounts deferred as regulatory assets and liabilities are subject to regulatory approval. As such, the regulatory authorities could alter the amounts subject to deferral, at which time the change would be reflected in the consolidated financial statements. Certain remaining recovery and settlement periods are those expected by management and the actual recovery or settlement periods could differ based on regulatory approval.

Inventories

Inventories, consisting of materials and supplies, gas and fuel in storage and coal, are measured at the lower of average cost and market value.

Utility Capital Assets

Utility capital assets are recorded at cost less accumulated depreciation. Contributions in aid of construction represent amounts contributed by customers and governments for the cost of utility capital assets. These contributions are recorded as a reduction in the cost of utility capital assets and are being amortized annually by an amount equal to the charge for depreciation provided on the related assets.

Each of UNS Energy, Central Hudson, the FortisBC Energy companies, FortisAlberta, Newfoundland Power and Maritime Electric accrue estimated non-ARO removal costs in depreciation, as required by their respective regulator, with the amount provided for in depreciation recorded as a long-term regulatory liability (Note 7 (xvii)). Actual non-ARO removal costs, net of salvage proceeds, are recorded against the regulatory liability when incurred. During 2014 non-ARO removal costs of $88 million (2013 - $73 million) were accrued by the above-noted utilities as part of depreciation and actual non-ARO removal costs of $16 million (2013 - $14 million), net of salvage proceeds, were incurred and recognized against the long-term regulatory liability (Note 7 (xvii)).

As permitted by the regulator, FortisBC Electric records actual non-ARO removal costs, net of salvage proceeds, against accumulated depreciation as incurred. During 2014 actual non-ARO removal costs of approximately $8 million (2013 - $1 million), net of salvage proceeds of less than $1 million (2013 - less than $1 million), were incurred at FortisBC Electric.

FortisOntario and Fortis Turks and Caicos recognize non-ARO removal costs, net of salvage proceeds, in earnings in the period incurred. Caribbean Utilities recognizes non-ARO removal costs in utility capital assets.

Utility capital assets are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal of utility capital assets, any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation by UNS Energy, Central Hudson, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric, Caribbean Utilities and the FortisBC Energy companies effective January 1, 2014, as required by their respective regulator, with no gain or loss, if any, recognized in earnings. It is expected that any gains or losses charged to accumulated depreciation will be reflected in future depreciation expense when they are refunded or collected in customer electricity and gas rates. Prior to January 1, 2014, the FortisBC Energy companies recorded any remaining net book value, net of salvage proceeds, upon retirement or disposal of utility capital assets in a regulatory deferral account for recovery from customers in future rates, subject to regulatory approval (Note 7 (ix)).

At FortisOntario and Fortis Turks and Caicos, the regulators require that any remaining net book value, net of salvage proceeds, upon retirement or disposal of utility capital assets be recognized immediately in earnings.

As required by their respective regulator, UNS Energy, Central Hudson, the FortisBC Energy companies, FortisBC Electric, Newfoundland Power, Maritime Electric, Caribbean Utilities and Fortis Turks and Caicos, capitalize overhead costs that are not directly attributable to specific utility capital assets but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized general overhead costs to utility capital assets is established by the respective regulator.

As required by their respective regulator, UNS Energy, Central Hudson, the FortisBC Energy companies, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric and Caribbean Utilities include in the cost of utility capital assets both a debt and an equity component in the allowance for funds used during construction ("AFUDC"). The debt component of AFUDC is reported as a reduction of finance charges (Note 24) and the equity component of AFUDC is reported as other income (Note 23). Both components of AFUDC are charged to earnings through depreciation expense over the estimated service lives of the applicable utility capital assets. AFUDC is calculated in a manner as prescribed by the respective regulator.

At FortisAlberta, the cost of utility capital assets also includes Alberta Electric System Operator ("AESO") contributions, which are investments required by FortisAlberta to partially fund the construction of transmission facilities.

As approved by the regulator, FEVI has reduced the amounts reported for utility capital assets by the amount of government loans received in connection with the construction and operation of the Vancouver Island natural gas pipeline. As the loans are repaid and replaced with non-government loans, FEVI increases both utility capital assets and long-term debt (Note 14).

Utility capital assets include inventories held for the development, construction and betterment of other utility capital assets, with the exception of UNS Energy. As required by its regulator, UNS Energy recognizes inventories held for the development and construction of other utility capital assets in inventories until consumed. When put into service, the inventories are reclassified to utility capital assets (Note 6).

Maintenance and repairs of utility capital assets are charged to earnings in the period incurred, while replacements and betterments which extend the useful lives are capitalized.

Utility capital assets are depreciated using the straight-line method based on the estimated service lives of the utility capital assets. Depreciation rates for 2014 ranged from 1.3% to 43.2% (2013 - 1.3% to 43.2%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, for 2014 was 3.2% (2013 - 3.3%).

The service life ranges and weighted average remaining service life of the Corporation's distribution, transmission, generation and other assets as at December 31 were as follows:

20142013
Weighted Weighted
Average Average
Service LifeRemainingService LifeRemaining
(Years)RangesService LifeRangesService Life
Distribution
Electric5-80285-8031
Gas4-85397-8539
Transmission
Electric20-702720-7031
Gas4-71388-7038
Generation4-75244-7530
Other3-7083-708

Non-Utility Capital Assets

Non-utility capital assets, which include office buildings, shopping malls, hotels, land, construction in progress, and related equipment and tenant inducements, are recorded at cost less accumulated depreciation, where applicable. Buildings are depreciated using the straight-line method over an estimated useful life of 60 years. Tenant inducements are depreciated over the initial terms of the leases to which they relate, except w