Fortis Delivers Earnings of $198 Million for the First Quarter of 2015

05/05/2015 06:30 EST

- $900 Million Waneta Hydroelectric Expansion Online and Generating Power

- 2015 Capital Expenditure Program Expected to Surpass $2 Billion

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -

Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) released its first quarter results today.

"Fortis is positioned for a strong 2015 based on the performance of our major utilities in the first quarter," says Barry Perry, President and Chief Executive Officer, Fortis. "Also, the $900 million, 335-megawatt Waneta Expansion hydroelectric generating facility in British Columbia came online early April, six weeks ahead of schedule and on budget, while maintaining an excellent safety and environmental protection record. The facility will contribute to earnings beginning in the second quarter," he continues.

Net earnings attributable to common equity shareholders for the first quarter were $198 million, or $0.72 per common share, compared to $143 million, or $0.67 per common share, for the first quarter of 2014. Excluding a number of one-time impacts, adjusted net earnings attributable to common equity shareholders for the first quarter were $179 million, or $0.65 per common share, compared to $146 million, or $0.68 per common share, for the first quarter of 2014. While UNS Energy contributed $20 million to earnings in the first quarter, as expected the acquisition had a $0.13 dilutive impact on earnings per common share, after considering the common share offering and finance charges associated with the acquisition. The earnings of UNS Energy are highly seasonal, with approximately 75% of earnings contributed in the second and third quarters.

"Our enterprise-wide capital program is expected to surpass $2 billion this year and is well advanced, with more than $550 million invested in the first quarter," says Perry. FortisBC's Tilbury liquefied natural gas ("LNG") expansion (known as Tilbury 1A), at an estimated total cost of approximately $440 million, is the largest capital project ongoing. Tilbury 1A will add 950,000 mmBtus of storage and 34,000 mmBtus daily of liquefaction when the second LNG tank and new liquefier come in service, which is expected to occur by the end of 2016.

In January 2015 UNS Energy closed the purchase of an additional ownership interest in the Springerville Unit 1 generating facility for US$46 million, as expected, following the expiry of the lease agreement. UNS Energy's ownership interests in Springerville Unit 1 now total 49.5%.

"A number of significant regulatory processes were concluded in the quarter, ensuring ongoing regulatory stability for our utilities," says Perry. "In addition to the proceedings concluded in Alberta, our application for new rates in New York State was advanced as well," he explains.

At FortisAlberta, regulatory decisions were received in March 2015 on the utility's Capital Tracker Applications and the Generic Cost of Capital ("GCOC") Proceeding. The Capital Tracker Decision approved revenue for substantially all of FortisAlberta's capital programs as filed; previously, revenue was recognized on an interim basis at 60% of the applied for amounts. The GCOC Proceeding set the utility's allowed rate of return on common shareholder's equity ("ROE") for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The impact of the decreases in the allowed ROE and common equity component of capital structure only applies to the portion of FortisAlberta's revenue that is associated with capital tracker amounts throughout the term of the performance-based rate setting regulation. As a result of these regulatory decisions, in the first quarter of 2015, FortisAlberta recognized a positive $10 million capital tracker revenue adjustment associated with 2013 and 2014.

At Central Hudson, a Joint Settlement Proposal was filed in February 2015 that proposes new rates at the utility 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. 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. Public statement and evidentiary hearings were held in March 2015 and a Final Joint Proposal was executed in April 2015. The Final Joint Settlement Proposal is targeted to go to the regulator in June for consideration and approval.

"Fortis remains focused on our core regulated utility business and long-term contracted energy infrastructure", explains Perry. "We expect to make an announcement regarding the outcome of the strategic review of Fortis Properties in the second quarter of 2015," he says.

In March 2015 the Corporation entered into an agreement to sell its non-regulated generation assets in Upstate New York and Ontario. The sale of the generation assets in Upstate New York and Ontario is expected to close in the second quarter of 2015 and the second half of 2015, respectively.

Fortis continues to be one of the highest-rated utility holding companies in North America, with its corporate debt rated A- by Standard and Poor's and A(low) by DBRS, which helps ensure efficient access to capital. In February 2015 Tucson Electric Power Company, UNS Energy's largest utility, issued US$300 million 10-year senior unsecured notes at 3.05%. Net proceeds were primarily used to repay long-term debt and credit facility borrowings and to finance capital expenditures. UNS Energy and its regulated utilities received credit rating upgrades from Moody's Investor Service in the first quarter of 2015.

"Fortis continues to build on its dividend record to shareholders," says Perry. The Corporation paid a quarterly dividend of $0.34 per common share on March 1, 2015 compared to $0.32 paid on December 1, 2014. The 6.25% increase extends the Corporation's record of annualized common share dividend increases to 42 consecutive years, the longest record of any public corporation in Canada.

"Following a decade of growth driven mainly by acquisitions, Fortis has entered a period of significant organic growth," says Perry.

Over the five-year period through 2019, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase midyear rate base by approximately 38% from $14 billion in 2014 to more than $19 billion in 2019 and produce a five-year compound annual growth rate ("CAGR") of approximately 6.5%. Two new natural gas infrastructure investments in British Columbia that Fortis is pursuing - Tilbury 1B and the pipeline expansion to Woodfibre LNG - could increase the five-year CAGR in rate base to 7.5%.

"Looking out over the five-year horizon, we expect our capital investment to support continuing growth in earnings and dividends," concludes Perry.

Teleconference to Discuss First Quarter 2015 Results

A teleconference and webcast will be held on May 5 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 first quarter 2015 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 May 15, 2015. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 13991420.

Interim Management Discussion and Analysis

For the three months ended March 31, 2015

Dated May 5, 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 interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 2015 and the MD&A and audited consolidated financial statements for the year ended December 31, 2014 included in the Corporation's 2014 Annual Report. Financial information 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 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; forecast midyear rate base and the associated compound annual growth rate through 2019; the nature, timing and expected costs of certain capital projects including, without limitation, the Tilbury liquefied natural gas ("LNG") facility expansion, the pipeline expansion to Woodfibre LNG, 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 fixed-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 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 Corporation's 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: 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; 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; sufficient liquidity and capital resources; 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; no significant changes in tax legislation; 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 related to litigation; 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 approximately $28 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.

Year-to-date March 31, 2015, the Corporation's electricity distribution systems met a combined peak demand of 8,455 megawatts ("MW") and its gas distribution system met a peak day demand of 1,198 terajoules. For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2015 and to the "Corporate Overview" section of the 2014 Annual MD&A.

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 may be 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.

SIGNIFICANT ITEMS

Completion of the Waneta Expansion Hydroelectric Generating Facility: On April 1, 2015, the Corporation completed construction of the $900 million, 335-MW Waneta Expansion hydroelectric generating facility (the "Waneta Expansion") ahead of schedule and on budget. Fortis has a 51% controlling ownership interest in the Waneta Expansion, with Columbia Power Corporation and Columbia Basin Trust holding the remaining 49% interest. 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. For further information regarding the Waneta Expansion, refer to the "Capital Expenditure Program" section of this MD&A.

Regulatory Decisions at FortisAlberta: In March 2015 regulatory decisions were received on FortisAlberta's Capital Tracker Applications and the Generic Cost of Capital ("GCOC") Proceeding in Alberta. The Capital Tracker Decision approved revenue for substantially all of FortisAlberta's capital programs as filed; previously, revenue was recognized on an interim basis at 60% of the applied for amounts. The GCOC Proceeding set FortisAlberta's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The impact of the decreases in the allowed ROE and common equity component of capital structure only applies to the portion of FortisAlberta's revenue that is associated with capital tracker amounts throughout the term of the PBR regulation. As a result of these regulatory decisions, in the first quarter of 2015, FortisAlberta recognized a positive $10 million capital tracker revenue adjustment associated with 2013 and 2014. This adjustment reflects the combined impact of the Capital Tracker Decision and the GCOC Decision, taking into consideration the capital tracker revenue previously recognized on an interim basis for 2013 and 2014 at 60% of the applied for amounts. For further details on these regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.

Sale of Non-Regulated Generation Assets: In March 2015 the Corporation entered into an agreement to sell its non-regulated generation assets in Upstate New York and Ontario. The sale of the generation assets in Upstate New York and Ontario is expected to close in the second quarter of 2015 and the second half of 2015, respectively. As a result, the associated assets and liabilities have been classified as held for sale on the Corporation's interim unaudited consolidated balance sheet as at March 31, 2015. A gain on the sale is expected to be recognized in earnings at the time of closing.

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of profitable growth with earnings per common share and total shareholder return as the primary measures of performance. The Corporation's business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the first quarters ended March 31, 2015 and 2014 are provided in the following table.

Consolidated Financial Highlights (Unaudited) Quarter Ended March 31
($ millions, except for common share data) 2015 2014 Variance
Revenue 1,915 1,455 460
Energy Supply Costs 833 679 154
Operating Expenses 473 319 154
Depreciation and Amortization 215 148 67
Other Income (Expenses), Net 17 7 10
Finance Charges 134 123 11
Income Tax Expense 57 39 18
Earnings from Continuing Operations 220 154 66
Earnings from Discontinued Operations, Net of Tax - 5 (5 )
Net Earnings 220 159 61
Net Earnings Attributable to:
Non-Controlling Interests 2 2 -
Preference Equity Shareholders 20 14 6
Common Equity Shareholders 198 143 55
Net Earnings 220 159 61
Earnings per Common Share from Continuing Operations
Basic ($) 0.72 0.65 0.07
Diluted ($) 0.71 0.64 0.07
Earnings per Common Share
Basic ($) 0.72 0.67 0.05
Diluted ($) 0.71 0.66 0.05
Weighted Average Number of Common Shares
Outstanding (# millions) 276.7 213.6 63.1
Cash Flow from Operating Activities 450 265 185

Revenue

The increase in revenue was driven by the acquisition of UNS Energy in August 2014. Favourable foreign exchange associated with the translation of US dollar-denominated revenue and a capital tracker revenue adjustment of approximately $10 million at FortisAlberta also contributed to the increase. The increase was partially offset by lower gas volumes at FortisBC Energy.

Energy Supply Costs

The increase in energy supply costs was primarily due to the acquisition of UNS Energy and unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs. The increase was partially offset by lower gas volumes at FortisBC Energy, which decreased natural gas purchases.

Operating Expenses

The increase in operating expenses was primarily due to the acquisition of UNS Energy, unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses and general inflationary and employee-related cost increases.

Depreciation and Amortization

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

Other Income (Expenses), Net

The increase in other income, net of expenses, was mainly due to favourable foreign exchange on the translation of the Corporation's US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity Limited ("Belize Electricity").

Finance Charges

The increase in finance charges was primarily due to the acquisition of UNS Energy, including interest expense on debt issued to complete the financing of the acquisition. The increase was partially offset by lower interest on convertible debentures. Approximately $16 million ($11 million after tax) in interest expense was recognized in the first quarter of 2014 associated with convertible debentures issued to finance a portion of the acquisition of UNS Energy. In October 2014 the convertible debentures were substantially all converted into common shares of the Corporation.

Income Tax Expense

The increase in income tax expense was primarily due to higher earnings before income taxes, driven by the acquisition of UNS Energy.

Net Earnings Attributable to Common Equity Shareholders and Basic Earnings Per Common Share

Net earnings attributable to common equity shareholders were impacted by a number of non-recurring items or non-operating factors. These factors, referred to as adjusting items, are reconciled below and discussed in the segmented results of operations for the respective reporting segments. Management believes that adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share provides useful information to investors and shareholders as it provides increased transparency and predictive value. The adjusting items do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar measures presented by other companies.

Non-US GAAP Reconciliation (Unaudited) Quarter Ended March 31
($ millions, except for common share data) 2015 2014 Variance
Net Earnings Attributable to Common Equity Shareholders 198 143 55
Adjusting Items:
FortisAlberta -
Capital tracker revenue adjustment for 2013 and 2014 (10 ) - (10 )
Non-Utility -
Earnings from discontinued operations - (5 ) 5
Corporate and Other -
Foreign exchange gain (9 ) (4 ) (5 )
Interest expense on convertible debentures - 11 (11 )
Acquisition-related expenses - 1 (1 )
Adjusted Net Earnings Attributable to Common
Equity Shareholders 179 146 33
Adjusted Basic Earnings Per Common Share ($) 0.65 0.68 (0.03 )

The increase in adjusted net earnings attributable to common equity shareholders for the quarter was driven by the Corporation's regulated utilities. UNS Energy contributed earnings of $20 million in the first quarter of 2015. Earnings at FortisBC Energy and FortisBC Electric were $9 million and $5 million, respectively, higher quarter over quarter, largely due to timing of quarterly earnings compared to the same periods last year resulting from the impact of regulatory deferral mechanisms. FortisAlberta's earnings were favourably impacted by higher capital tracker revenue for 2015 and customer growth. Central Hudson and Eastern Canadian Regulated Electric Utilities also reported improved performance.

The increase in earnings at the regulated utilities was partially offset by lower earnings at the Corporation's non-regulated subsidiaries, largely due to decreased production in Belize as a result of lower rainfall and costs at Fortis Properties associated with the ongoing strategic review. Higher preference share dividends and finance charges in the Corporate and Other segment associated with the acquisition of UNS Energy decreased earnings for the first quarter of 2015.

The decrease in adjusted earnings per common share was primarily due to the $0.13 dilutive impact of the acquisition of UNS Energy, after considering the finance charges associated with the acquisition and the increase in the weighted average number of common shares outstanding. The earnings of UNS Energy are highly seasonal, with approximately 75% of earnings contributed in the second and third quarters. The decrease in adjusted earnings per common share was partially offset by other increases in adjusted net earnings attributable to common equity shareholders, as discussed above.

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited) Quarter Ended March 31
($ millions) 2015 2014 Variance
Regulated Gas & Electric Utilities - United States
UNS Energy 20 - 20
Central Hudson 22 18 4
42 18 24
Regulated Gas Utility - Canadian
FortisBC Energy 88 79 9
Regulated Electric Utilities - Canadian
FortisAlberta 41 25 16
FortisBC Electric 23 18 5
Eastern Canadian 19 17 2
83 60 23
Regulated Electric Utilities - Caribbean 5 5 -
Non-Regulated - Fortis Generation 3 6 (3 )
Non-Regulated - Non-Utility (2 ) 5 (7 )
Corporate and Other (21 ) (30 ) 9
Net Earnings Attributable to Common Equity Shareholders 198 143 55

The following is a discussion of the financial results of the Corporation's reporting segments. Refer to the "Material Regulatory Decisions and Applications" section of this MD&A for a discussion pertaining to the Corporation's regulated utilities.

REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES

UNS ENERGY (1)

Financial Highlights (Unaudited) Quarter
Period Ended March 31 2015
Average US:CDN Exchange Rate (2) 1.24
Electricity Sales (gigawatt hours ("GWh")) 3,397
Gas Volumes (petajoules ("PJ")) 5
Revenue ($ millions) 435
Earnings ($ millions) 20
(1) Primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"), acquired by Fortis in August 2014
(2) The reporting currency of UNS Energy is the US dollar.

Electricity Sales & Gas Volumes

Electricity sales for the first quarter were 3,397 gigawatt hours ("GWh") compared to 3,199 GWh for the same period last year. The increase was primarily due to an increase in short-term wholesale sales as a result of more favourable commodity prices compared to the same period last year. Short-term wholesale sales are flowed through to customers and have no impact on earnings.

Gas volumes for the first quarter were 5 petajoules ("PJ"), comparable with the same period last year.

Seasonality impacts the earnings 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. In 2014 approximately 75% of UNS Energy's earnings were recognized in the second and third quarters, excluding acquisition-related expenses.

Revenue

Revenue for the first quarter was US$350 million compared to US$333 million for the same period last year. The increase was primarily due to the flow through to customers of higher purchased power and fuel supply costs as a result of the operation of UNS Energy's regulatory cost recovery mechanisms.

Earnings

Earnings for the first quarter were approximately US$17 million, comparable with the same period last year.

CENTRAL HUDSON

Financial Highlights (Unaudited) Quarter Ended March 31
2015 2014 Variance
Average US:CDN Exchange Rate (1) 1.24 1.10 0.14
Electricity Sales (GWh) 1,415 1,407 8
Gas Volumes (PJ) 11 10 1
Revenue ($ millions) 292 272 20
Earnings ($ millions) 22 18 4
(1) The reporting currency of Central Hudson is the US dollar.

Electricity Sales & Gas Volumes

Electricity sales and gas volumes for the first quarter of 2015 were comparable with the same period last year.

Seasonality impacts delivery revenue at Central Hudson, as electricity sales are highest during the summer months, primarily due to the use of air conditioning and other cooling equipment, and gas volumes are highest during the winter months, primarily due to space-heating usage.

Revenue

The increase in revenue was due to approximately $32 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. The recovery of deferred electricity and gas costs, higher gas revenue associated with a new contract in late 2014, as well as energy-efficiency incentives earned during the quarter upon achieving energy saving targets established by the regulator, also contributed to the increase in revenue. The increase was partially offset by the recovery from customers of lower commodity costs, which were mainly due to lower wholesale prices.

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

The increase in earnings was primarily due to approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings. A new gas contract in late 2014 and energy-efficiency incentives earned during the quarter, as discussed above, also contributed to the increase in earnings, and were partially offset by the impact of higher operating expenses during the two-year rate freeze period post acquisition in June 2013.

REGULATED GAS UTILITY - CANADIAN

FORTISBC ENERGY (1)

Financial Highlights (Unaudited) Quarter Ended March 31
2015 2014 Variance
Gas Volumes (PJ) 62 75 (13 )
Revenue ($ millions) 488 513 (25 )
Earnings ($ millions) 88 79 9
(1) Primarily includes FortisBC Energy Inc. ("FEI") and, prior to December 31, 2014, FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"). On December 31, 2014, FEI, FEVI and FEWI were amalgamated and FEI is the resulting Company.

Gas Volumes

The decrease in gas volumes was primarily due to lower average consumption as a result of warmer temperatures.

FortisBC Energy earns 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.

Seasonality has a material impact on the earnings of FortisBC Energy as a major portion of the gas distributed is used for space heating. Most of the annual earnings of FortisBC Energy are realized in the first and fourth quarters.

Revenue

The decrease in revenue was primarily due to lower gas volumes, partially offset by a higher commodity cost of natural gas charged to customers and the timing of regulatory flow-through deferral amounts. Prior to the amalgamation of FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI"), and FortisBC Energy (Whistler) Inc. ("FEWI") on December 31, 2014, FEVI was subject to a rate stabilization mechanism which accumulated the difference between revenue received and actual cost of service, thereby reducing the seasonality of revenue and earnings. As a result of the amalgamation, effective January 1, 2015, this rate stabilization mechanism ceased, resulting in greater seasonality whereby revenue and earnings will be higher in the first and fourth quarters and lower in the second and third quarters.

Earnings

The increase in earnings was driven by approximately $12 million associated with the timing of regulatory flow-through deferral amounts, as discussed above. This increase was partially offset by a decrease in the allowed ROE and equity component of capital structure as a result of the amalgamation of FEVI and FEWI with FEI, effective December 31, 2014. Prior to the amalgamation, the allowed ROEs for FEVI and FEWI were 9.25% and 9.50%, respectively, on a common equity component of capital structure of 41.5%. Effective January 1, 2015, the allowed ROE and common equity component of capital structure revert to those of FEI, which are 8.75% and 38.5%, respectively.

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited) Quarter Ended March 31
2015 2014 Variance
Energy Deliveries (GWh) 4,667 4,683 (16 )
Revenue ($ millions) 146 126 20
Earnings ($ millions) 41 25 16

Energy Deliveries

The decrease in energy deliveries was primarily due to lower average consumption by residential, commercial and farm and irrigation customers due to warmer temperatures, partially offset by growth in the number of customers. The total number of customers increased by approximately 12,000 year over year as at March 31, 2015, driven by residential customers as a result of favorable economic conditions in Alberta in 2014.

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 a $10 million capital tracker revenue adjustment recognized in the first quarter of 2015 associated with 2013 and 2014, as discussed below, and higher revenue resulting from the operation of the PBR formula, including an increase in customer rates based on a combined inflation and productivity factor of 1.49% and higher 2015 capital tracker revenue. Growth in the number of customers and higher revenue related to flow-through costs to customers also contributed to the increase in revenue.

In March 2015 regulatory decisions were received on FortisAlberta's Capital Tracker Applications and the GCOC Proceeding in Alberta. The Capital Tracker Decision approved revenue for substantially all of FortisAlberta's capital programs as filed; previously, revenue was recognized on an interim basis at 60% of the applied for amounts. The GCOC Proceeding set the utility's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The impact of the decreases in the allowed ROE and common equity component of capital structure only applies to the portion of FortisAlberta's revenue that is associated with capital tracker amounts throughout the term of the PBR regulation. The $10 million capital tracker revenue adjustment associated with 2013 and 2014 reflects the combined impact of the Capital Tracker Decision and the GCOC Decision, taking into consideration the capital tracker revenue previously recognized on an interim basis for 2013 and 2014 at 60% of the applied for amounts. For further details on these regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of the MD&A.

Earnings

The increase in earnings was driven by capital tracker revenue of approximately $10 million recognized in the first quarter of 2015 associated with 2013 and 2014, as discussed above, as well as rate base growth and associated 2015 capital tracker revenue and growth in the number of customers.

FORTISBC ELECTRIC (1)

Financial Highlights (Unaudited) Quarter Ended March 31
2015 2014 Variance
Electricity Sales (GWh) 839 907 (68 )
Revenue ($ millions) 96 95 1
Earnings ($ millions) 23 18 5
(1) Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned Walden Power Partnership.

Electricity Sales

The decrease in electricity sales was mainly due to lower average consumption as a result of warmer temperatures.

Revenue

Revenue for the first quarter of 2015 was comparable to the same period last year. An interim refundable increase in base electricity rates, effective January 1, 2015, and the amortization of regulatory deferral adjustments owing to customers were largely offset by lower electricity sales.

Earnings

The increase in earnings was primarily due to the timing of earnings compared to the same period last year as a result of the impact of regulatory deferral mechanisms, timing of power purchase costs and rate base growth.

EASTERN CANADIAN ELECTRIC UTILITIES (1)

Financial Highlights (Unaudited) Quarter Ended March 31
2015 2014 Variance
Electricity Sales (GWh) 2,759 2,716 43
Revenue ($ millions) 322 312 10
Earnings ($ millions) 19 17 2
(1) Comprised of Newfoundland Power, Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and Algoma Power.

Electricity Sales

The increase in electricity sales was driven by customer growth and higher average consumption in Newfoundland and Prince Edward Island, including an increase in the number of customers using electricity for home heating. The increase was partially offset by lower average consumption by residential customers in Ontario.

Revenue

The increase in revenue was primarily due to electricity sales growth and the flow through in customer electricity rates of higher energy supply costs at FortisOntario.

Earnings

The increase in earnings was primarily due to electricity sales growth and lower operating costs associated with restoration efforts at Newfoundland Power following the loss of energy supply from Newfoundland and Labrador Hydro and related power interruptions in January 2014.

REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)

Financial Highlights (Unaudited) Quarter Ended March 31
2015 2014 Variance
Average US:CDN Exchange Rate (2) 1.24 1.10 0.14
Electricity Sales (GWh) 180 180 -
Revenue ($ millions) 78 74 4
Earnings ($ millions) 5 5 -
(1) Comprised of Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 60% controlling interest, and two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos")
(2) The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar.

Electricity Sales

Electricity sales for the quarter were consistent with the same period last year.

Revenue

The increase in revenue was driven by approximately $9 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, partially offset by the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities.

Earnings

Earnings for the quarter were consistent with the same period last year. Foreign exchange associated with the translation of US dollar-denominated earnings had a slightly favourable impact on earnings, which was largely offset by higher depreciation.

NON-REGULATED - FORTIS GENERATION (1)

Financial Highlights (Unaudited) Quarter Ended March 31
2015 2014 Variance
Energy Sales (GWh) 60 99 (39 )
Revenue ($ millions) 7 11 (4 )
Earnings ($ millions) 3 6 (3 )
(1) Comprised of the financial results of non-regulated generation assets in Belize, Ontario, British Columbia and Upstate New York, with a combined generating capacity of 103 MW, mainly hydroelectric. On April 1, 2015, the Corporation completed construction of the $900 million, 335-MW Waneta Expansion. For further information, refer to the "Capital Expenditure Program" section of this MD&A.

Energy Sales

The decrease in energy sales was primarily due to decreased production in Belize due to lower rainfall. Decreased production in Upstate New York and Ontario, due to lower rainfall and generating units taken out of service for repairs, also contributed to the overall decrease in energy sales.

Revenue

The decrease in revenue was primarily due to decreased production in Belize, Upstate New York and Ontario.

Earnings

The decrease in earnings was primarily due to decreased production in Belize, Upstate New York and Ontario, partially offset by $1 million in business development costs in the first quarter of 2014 associated with investigating a potential generating facility in British Columbia.

NON-REGULATED - NON-UTILITY (1)

Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2015 2014 Variance
Revenue 53 54 (1 )
(Loss) Earnings (2 ) 5 (7 )
(1) Comprised of Fortis Properties and 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. Griffith was acquired in June 2013 as part of the acquisition of CH Energy Group 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 to March 2014.

Revenue

Revenue at Fortis Properties for the first quarter of 2015 was comparable to the same period last year.

Earnings

Fortis Properties generated a loss of approximately $2 million in the first quarter of 2015 compared to earnings of less than $0.5 million for the same period last year. The decrease in earnings was primarily due to costs associated with the ongoing strategic review, as discussed below, and higher finance charges. Earnings for the first quarter of 2014 include $5 million associated with Griffith from normal operations to the date of sale.

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. An announcement on the outcome of the strategic review is expected to be made in the second quarter of 2015.

CORPORATE AND OTHER (1)

Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2015 2014 Variance
Revenue 7 7 -
Operating Expenses 5 5 -
Other Income (Expenses), Net 9 2 7
Finance Charges 21 33 (12 )
Income Tax Recovery (9 ) (13 ) 4
(1 ) (16 ) 15
Preference Share Dividends 20 14 6
Net Corporate and Other Expenses (21 ) (30 ) 9
(1) Includes Fortis net Corporate expenses; non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group, Inc. and UNS Energy Corporation; and the financial results of FHI's wholly owned subsidiary FortisBC Alternative Energy Services Inc.

Net Corporate and Other expenses were impacted by the following items:

  1. A foreign exchange gain of approximately $9 million in the first quarter of 2015, compared to approximately $4 million for the same period last year, 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;
  2. Finance charges of $16 million ($11 million after tax) in the first quarter of 2014 associated with the convertible debentures issued in January 2014 to finance a portion of the acquisition of UNS Energy; and
  3. Other expenses of $2 million ($1 million after tax) in the first quarter of 2014 related to the acquisition of UNS Energy.

Excluding the above-noted items, net Corporate and Other expenses were $30 million for the first quarter of 2015 compared to $22 million for the same period last year. The increase was primarily due to higher preference share dividends and finance charges associated with the acquisition of UNS Energy in August 2014. Finance charges were also impacted by unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense.

MATERIAL REGULATORY DECISIONS AND APPLICATIONS

The nature of regulation associated with each of the Corporation's regulated electric and gas utilities is generally consistent with that disclosed in the 2014 Annual MD&A. The following summarizes the significant regulatory decisions and applications for the Corporation's regulated utilities in the first quarter of 2015.

Central Hudson

In July 2014 Central Hudson filed a General Rate Application ("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 and evidentiary hearings were held in March 2015 and a Final Joint Proposal was executed in April 2015. The Final Joint Settlement Proposal is targeted to go to the regulator in June for consideration and approval.

FortisBC Energy and FortisBC Electric

On December 31, 2014, FEI, FEVI and FEWI were amalgamated, as approved by the British Columbia Utilities Commission ("BCUC") in February 2014, and FEI is the resulting Company. Prior to the amalgamation, the allowed ROEs for FEVI and FEWI were 9.25% and 9.50%, respectively, on a common equity component of capital structure of 41.5%. Effective January 1, 2015, the allowed ROE and common equity component of capital structure revert to those of FEI, which are 8.75% and 38.5%, respectively.

In compliance with the PBR decisions issued by the BCUC in September 2014, in January and February 2015, FEI and FortisBC Electric, respectively, filed for approval of their 2015 rates under the PBR decisions. 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 formulaic approach for operating and maintenance costs and capital costs. A decision on the final rate increases is expected in the second quarter of 2015.

FEI is required to file an application to review the 2016 benchmark allowed ROE and common equity component of capital structure by no later than November 30, 2015. As FEI is the benchmark utility, the review of the application could have an impact on FortisBC Electric.

FortisAlberta

In March 2015 the Alberta Utilities Commission ("AUC") issued its decision on the GCOC Proceeding in Alberta. The GCOC Proceeding set FortisAlberta's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The AUC also decided that it will not re-establish a formula-based approach to setting the allowed ROE on an annual basis. The allowed ROE of 8.30% and common equity component of capital structure of 40% will remain in effect for 2016 and beyond on an interim basis. For regulated utilities in Alberta under PBR mechanisms, including FortisAlberta, the allowed ROE and common equity component of capital structure resulting from the GCOC Proceeding applies only to the portion of revenue that is associated with capital tracker amounts throughout the term of the PBR regulation.

In March 2015 the AUC also issued its decision related to FortisAlberta's 2013, 2014 and 2015 Capital Tracker Applications. The decision: (i) indicated which capital programs met the criteria established in the original PBR decision and were, therefore, approved for collection from customers; (ii) approved FortisAlberta's accounting test; and (iii) provided clarification on certain inputs to be used in the accounting test, including the conclusion that the weighted average cost of capital used in the accounting test is to be based on actual debt rates and the allowed ROE and capital structure approved in the GCOC Proceeding. Substantially all of FortisAlberta's capital programs were approved as filed.

FortisAlberta completed the required Capital Tracker Compliance Filing in April 2015, requesting that the adjustments to capital tracker revenue be considered in the 2016 Annual Rates Application to be filed in September 2015 and reflected in customer rates effective January 1, 2016. A decision on the Capital Tracker Compliance Filing is expected in the second half of 2015.

Additional capital tracker revenue of approximately $10 million was recognized in the first quarter of 2015 related to 2013 and 2014 capital expenditures. This adjustment reflects the combined impact of the Capital Tracker Decision and the GCOC Decision, taking into consideration the capital tracker revenue previously recognized on an interim basis for 2013 and 2014 at 60% of the applied for amounts. Capital tracker revenue for 2015 also reflects the impact of both decisions, taking into consideration the estimated 2015 capital expenditures related to qualifying capital programs.

In May 2015 FortisAlberta will file an application with the AUC seeking capital tracker revenue for 2016 and 2017, as well as a true-up to the actual 2014 capital expenditures. As part of this application, the Company will provide more comprehensive information on the components of the capital program that were not fully approved in the Capital Tracker Decision, seeking approval of the related capital expenditures incurred in 2013, 2014 and 2015. A hearing related to this proceeding is scheduled for October 2015, with a decision from the AUC expected in the first quarter of 2016.

In April 2015 the AUC initiated a 2016 GCOC Proceeding. A pre-proceeding conference will be held in May 2015, after which the AUC will identify the issues it has determined to be in-scope for this proceeding. In addition, an informal roundtable discussion will be held in June 2015 to explore procedural alternatives that may expedite completion of the 2016 GCOC Proceeding in a timely manner.

Eastern Canadian Electric Utilities

Newfoundland Power is required to file a GRA on or before June 1, 2015 to establish customer electricity rates for 2016, unless otherwise directed by the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB"). In April 2015 Newfoundland Power filed an application with the PUB to defer the filing of its next GRA to on or before June 1, 2016 and to request a 2016 cost recovery deferral of $4 million. The application is currently under review by the PUB.

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 GRA July 2014 Second quarter of 2015
Reforming the Energy Vision Not applicable To be determined
FEI 2015 Annual Rates Application January 2015 Second quarter of 2015
FortisBC Electric 2015 Annual Rates Application February 2015 Second quarter of 2015
FortisAlberta Capital Tracker Compliance Filing April 2015 Second half of 2015
2016/2017 Capital Tracker Application May 2015 First quarter of 2016

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between March 31, 2015 and December 31, 2014.

Significant Changes in the Consolidated Balance Sheets (Unaudited) between March 31, 2015 and December 31, 2014

Balance Sheet Account
Increase
($ millions)
Explanation
Regulatory assets - current and long-term 116 The increase was mainly due to: (i) the impact of foreign exchange on the translation of US dollar-denominated regulatory assets; (ii) the reclassification of unamortized leasehold improvements at UNS Energy associated with Springerville Unit 1; (iii) an increase in regulatory deferred income taxes; and (iv) the deferral of various other costs, as permitted by the regulators.
Utility capital assets 863 The increase was primarily due to the impact of foreign exchange on the translation of US dollar-denominated utility capital assets and utility capital expenditures, partially offset by depreciation.
Goodwill 210 The increase was due to the impact of foreign exchange on the translation of US dollar-denominated goodwill.
Long-term debt (including current portion) 649 The increase was primarily due to the impact of foreign exchange on the translation of US-dollar denominated debt and the issuance of long-term debt at UNS Energy, Central Hudson and Fortis Turks and Caicos. The increase was partially offset by regularly scheduled debt repayments.
Shareholders' equity (before non-controlling interests) 452 The increase primarily related to: (i) 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; (ii) net earnings attributable to common equity shareholders for the three months ended March 31, 2015, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.

LIQUIDITY AND CAPITAL RESOURCES

The table below outlines the Corporation's sources and uses of cash for the three months ended March 31, 2015, as compared to the same period in 2014, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows (Unaudited) Quarter Ended March 31
($ millions) 2015 2014 Variance
Cash, Beginning of Period 230 72 158
Cash Provided by (Used in):
Operating Activities 450 265 185
Investing Activities (553 ) (110 ) (443 )
Financing Activities 156 301 (145 )
Effect of Exchange Rate Changes on Cash and Cash Equivalents 19 - 19
Less Cash Associated with Assets Held for Sale (3 ) - (3 )
Cash, End of Period 299 528 (229 )

Operating Activities: Cash flow from operating activities was $185 million higher quarter over quarter. The increase was primarily due to higher cash earnings, largely due to the acquisition of UNS Energy, and favourable changes in working capital associated with accounts receivable at FortisBC Energy and UNS Energy. The increase was partially offset by unfavorable changes in long-term regulatory deferrals at FortisBC Energy and FortisAlberta.

Investing Activities: Cash used in investing activities was $443 million higher quarter over quarter. The increase was driven by capital expenditures at UNS Energy and higher capital spending at FortisBC Energy, FortisBC Electric and FortisAlberta. Proceeds from the sale of Griffith in March 2014 of approximately $105 million (US$95 million) also contributed to the variance.

Financing Activities: Cash provided by financing activities was $145 million lower quarter over quarter. The decrease was primarily due to lower proceeds from the Corporation's convertible debentures and higher repayments of long-term debt, partially offset by higher proceeds from the issuance of long-term debt, lower net repayments of committed credit facility borrowings and changes in short-term borrowings.

In January 2014 proceeds of approximately $599 million, or $561 million net of issue costs, were received from the first installment of the convertible debentures issued to finance a portion of the acquisition of UNS Energy. Initially, a portion of the net proceeds were cash on hand, while a portion was used to repay borrowings under the Corporation's committed credit facility and for other general corporate purposes, including intercompany loan advances to subsidiaries.

Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for the quarter compared to the same period last year are summarized in the following tables.

Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Quarter Ended March 31
($ millions) 2015 2014 Variance
UNS Energy (1) 370 - 370
Central Hudson (2) 25 33 (8 )
Other (3) 12 - 12
Total 407 33 374
(1) In February 2015 TEP, UNS Energy's largest utility, issued 10-year US$300 million 3.05% senior unsecured notes. Net proceeds were primarily used to repay long-term debt and credit facility borrowings and to finance capital expenditures.
(2) In March 2015 Central Hudson issued 10-year US$20 million 2.98% unsecured notes. The net proceeds were used to finance capital expenditures and for general corporate purposes. 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 other general corporate purposes.
(3) In January 2015 Fortis Turks and Caicos issued 15-year US$10 million 4.75% unsecured notes. The net proceeds were used to finance capital expenditures and for general corporate purposes.
Repayments of Long-Term Debt and Capital Lease and Finance Obligations (Unaudited)
Quarter Ended March 31
($ millions) 2015 2014 Variance
UNS Energy (168 ) - (168 )
Central Hudson - (8 ) 8
FortisBC Energy (2 ) (1 ) (1 )
Other - (2 ) 2
Total (170 ) (11 ) (159 )
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)
Quarter Ended March 31
($ millions) 2015 2014 Variance
UNS Energy (87 ) - (87 )
FortisAlberta 46 (20 ) 66
FortisBC Electric - (79 ) 79
Newfoundland Power 19 - 19
Corporate 3 (46 ) 49
Total (19 ) (145 ) 126

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.

Common share dividends paid in the first quarter of 2015 were $60 million, net of $34 million of dividends reinvested, compared to $47 million, net of $22 million of dividends reinvested, paid in the same quarter of 2014. The dividend paid per common share for the first quarter of 2015 was $0.34 compared to $0.32 for the first quarter of 2014. The weighted average number of common shares outstanding for the first quarter of 2015 was 276.7 million compared to 213.6 million for the same quarter of 2014.

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 March 31, 2015, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2014 Annual MD&A and below, where applicable.

Contractual Obligations (Unaudited) Due Due
As at March 31, 2015 within Due in Due in Due in Due in after
($ millions) Total 1 year year 2 year 3 year 4 year 5 5 years
Long-term debt 11,150 513 758 88 313 172 9,306
Interest obligations on long-term debt 8,952 519 481 469 461 450 6,572
Capital lease and finance obligations 2,627 220 70 71 90 76 2,100
Renewable power purchase obligations 1,111 64 64 64 64 64 791
Long-term contracts - UNS Energy 1,103 137 136 122 95 110 503
Power purchase obligations (1) 1,040 251 228 181 147 62 171
Capital cost 527 19 21 19 22 19 427
Gas purchase contract obligations 299 218 21 16 12 8 24
Defined benefit pension funding contributions 183 77 28 11 8 9 50
Operating lease obligations 176 13 11 11 11 9 121
Renewable energy credit purchase agreements 154 11 11 11 11 11 99
Purchase of Springerville common facilities 134 - - 48 - - 86
Waneta Partnership promissory note 72 - - - - - 72
Joint-use asset and shared service agreements 53 3 3 3 3 3 38
Other 75 7 15 11 3 - 39
Total 27,656 2,052 1,847 1,125 1,240 993 20,399
(1) In March 2015 Maritime Electric extended its power purchase agreement with New Brunswick Power from March 2016 to February 2019, increasing the total commitment under this agreement by approximately $172 million as at March 31, 2015.

Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2014 Annual MD&A.

For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program not included in the preceding Contractual Obligations table, refer to the "Capital Expenditure Program" section of this MD&A.

CAPITAL STRUCTURE

The Corporation's principal businesses of regulated electric and gas utilities 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 (Unaudited) As at
March 31, 2015 December 31, 2014
($ millions) (%) ($ millions) (%)
Total debt and capital lease and finance 11,882 56.5 11,304 56.5
obligations (net of cash) (1)
Preference shares 1,820 8.7 1,820 9.1
Common shareholders' equity 7,323 34.8 6,871 34.4
Total (2) 21,025 100.0 19,995 100.0
(1) Includes long-term debt, capital lease and finance obligations, including current portion, 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 March 31, 2015 was 55.1% debt, 8.9% preference shares and 36.0% common shareholders' equity (December 31, 2014 - 55.0% debt, 9.4% preference shares and 35.6% common shareholders' equity).

The change in the capital structure was due to an increase in long-term debt, mainly due to the impact of foreign exchange on the translation of US-dollar denominated debt and the issuance of long-term debt, largely in support of energy infrastructure investment, partially offset by regularly scheduled debt repayments. The capital structure was also impacted by an increase in common shareholders' equity as a result of: (i) 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; (ii) net earnings attributable to common equity shareholders for the three months ended March 31, 2015, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.

CREDIT RATINGS

The Corporation's credit ratings are as follows:

Standard & Poor's ("S&P") A- / Stable (long-term corporate and unsecured debt credit rating)
DBRS A (low) / 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 reasonable levels of debt at the holding company level. In April 2015 S&P confirmed the Corporation's credit rating with a Stable outlook.

CAPITAL EXPENDITURE PROGRAM

A breakdown of the $554 million in gross consolidated capital expenditures by segment year-to-date 2015 is provided in the following table.

Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date March 31, 2015
($ millions)
Regulated Utilities Non-Regulated
Total
UNS Central FortisBC Fortis FortisBC Eastern Electric Regulated Fortis Non-
Energy Hudson Energy Alberta Electric Canadian Caribbean Utilities Generation Utility Total
193 33 118 106 32 35 21 538 11 5 554
(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 allowance for funds used during construction.

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 for 2015 are forecast to be approximately $2.2 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2014 Annual MD&A.

Construction of the $900 million, 335-MW Waneta Expansion was completed on April 1, 2015, ahead of schedule and on budget. The expansion adds a second powerhouse, immediately downstream of the Waneta Dam on the Pend d'Oreille River, that shares the existing hydraulic head and generates clean, renewable, cost-effective power from water that would otherwise be spilled. The project included construction of a 10-kilometre, 230-kilovolt transmission line and provides enough energy to power about 60,000 homes per year. On April 2, 2015, the Waneta Expansion began generating power, all of which will be sold to BC Hydro and FortisBC Electric under 40-year contracts.

Construction of FortisBC's Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury 1A") in Delta, British Columbia is ongoing. Key construction activities during the quarter focused on completion of the LNG tank concrete foundation and commencement of the tank wall and bottom steel plate. Tilbury 1A will be included in regulated rate base and is estimated to cost approximately $440 million, including an equity component of allowance for funds used during construction. It will include a second LNG tank and a new liquefier, both expected to be in service by the end of 2016.

FortisBC is pursuing additional LNG infrastructure investment opportunities, including a further $450 million expansion of Tilbury ("Tilbury 1B") and a $600 million pipeline expansion to the proposed LNG facility by Woodfibre LNG in Squamish, British Columbia. In December 2014 FortisBC received an Order in Council from the Government of British Columbia effectively exempting these projects from further regulatory approval by the British Columbia Utilities Commission; however, Tilbury 1B approval is conditional upon having long-term energy supply contracts in place for 70% of the additional liquefaction capacity, on average for the first 15 years of operation. FortisBC has a conditional contract with Hawaiian Electric Company that would meet this requirement, subject to the regulatory approval process in Hawaii. The pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG facility. These additional $1 billion of investment opportunities, which would be included in FortisBC's regulated rate base, are not included in the Corporation's capital expenditure forecast.

In January 2015, upon expiration of the Springerville Unit 1 lease, UNS Energy closed the purchase of an additional ownership interest in the unit for US$46 million. UNS Energy's ownership interests in Springerville Unit 1 now total 49.5%. Additionally, upon expiration of the Springerville Coal Handling Facilities lease in April 2015, UNS Energy purchased the previously leased coal-handling assets for US$73 million.

Over the five-year period through 2019, gross consolidated capital expenditures are expected to be approximately $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 37% at U.S. Regulated Electric & Gas Utilities; 36% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 20% at Canadian Regulated Gas Utility; 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: 50% for sustaining capital expenditures, 28% to meet customer growth, and 22% for facilities, equipment, vehicles, information technology and other assets.

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.

In April 2015 FortisBC Energy filed a short-form base shelf prospectus to establish a Medium Term Note Debenture Program under which FortisBC Energy may issue debentures in an aggregate principal amount of up to $1 billion during the 25-month life of the shelf prospectus. In April 2015 FortisBC Energy issued 30-year $150 million 3.375% unsecured debentures. The net proceeds were used to repay short-term borrowings.

As at March 31, 2015, management expects consolidated fixed-term debt maturities and repayments to average approximately $250 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.

Fortis and its subsidiaries were compliant with debt covenants as at March 31, 2015 and are expected to remain compliant throughout 2015.

CREDIT FACILITIES

As at March 31, 2015, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.8 billion, of which approximately $2.1 billion was unused, including $477 million unused under the Corporation's 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 $3.6 billion of the total credit facilities are committed facilities with maturities ranging from 2015 through 2020.

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

Credit Facilities (Unaudited) As at
Regulated Non- Corporate March 31, December 31,
($ millions) Utilities Regulated and Other 2015 2014
Total credit facilities (1) 2,169 13 1,621 3,803 3,854
Credit facilities utilized:
Short-term borrowings (362 ) - - (362 ) (330 )
Long-term debt (206 ) - (897 ) (1,103 ) (1,096 )
Letters of credit outstanding (170 ) - (34 ) (204 ) (192 )
Credit facilities unused 1,431 13 690 2,134 2,236
(1) Total credit facilities exclude a $300 million increase to the Corporation's committed corporate credit facility in March 2015, not syndicated by creditors as at March 31, 2015, as discussed below.

As at March 31, 2015 and December 31, 2014, 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.

The significant changes in available credit facilities from that disclosed in the Corporation's 2014 Annual MD&A are as follows.

In March 2015 the Corporation amended its $1 billion corporate committed credit facility, resulting in an increase in the facility to $1.3 billion and an extension of the maturity date to July 2020 from July 2018. As at March 31, 2015, the additional $300 million was not available for use as syndication by creditors was not finalized.

In March 2015 UNS Energy repaid its US$130 million non-revolving term loan commitment using net proceeds from the issuance of long-term debt.

In April 2015 FortisBC Electric amended its $150 million unsecured committed revolving credit facility to now mature in May 2018.

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 (Unaudited) As at
March 31, 2015 December 31, 2014
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
Waneta Partnership promissory note 53 58 53 56
Long-term debt, including current portion 11,150 13,339 10,501 12,237

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 Government of Belize ("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 $125 million as at March 31, 2015 (December 31, 2014 - $116 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 recurring basis. The fair values reflect point-in-time estimates based on current and relevant market information as at the balance sheet dates. 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 (Unaudited) As at
Fair value March 31, December 31,
($ millions) hierarchy 2015 2014
Assets
Energy contracts subject to regulatory deferral (1) (2) Level 3 2 3
Energy contracts not subject to regulatory deferral (1) (2) Level 3 - 1
Other investments (3) Levels 1/2 48 36
Total gross assets 50 40
Less: Counterparty netting not offset on the balance sheet (4) (2 ) (3 )
Total net assets 48 37
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (5) Levels 1/2/3 91 72
Energy contracts not subject to regulatory deferral (1) (2) Level 3 - 1
Energy contracts - cash flow hedges (2) (6) Level 3 1 1
Interest rate swaps - cash flow hedges (6) Level 2 5 5
Total gross liabilities 97 79
Less: Counterparty netting not offset on the balance sheet (4) (2 ) (3 )
Total net liabilities 95 76
(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 $13 million - level 1 and $35 million - level 2 (2014 - $5 million - level 1 and $31 million - level 2)
(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 $48 million - level 2 and $43 million - level 3 (2014 - $2 million - level 1, $35 million - level 2 and $35 million - level 3)
(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 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.

FortisBC Energy holds 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 March 31, 2015, 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 March 31, 2015, unrealized losses of $89 million (December 31, 2014 - $69 million) were recognized in current regulatory assets and no unrealized gains were recognized in regulatory liabilities.

Cash Flow Hedges

UNS Energy holds interest rate swaps, expiring through 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 12 months is estimated to be approximately $4 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 March 31, 2015, 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 9 993 659 219
Electricity power purchase contracts (GWh) 2017 39 1,101 718 145
Gas swap and option contracts (PJ) 2017 185 34 26 6
Gas purchase contract premiums (PJ) 2015 38 73 - -
Energy contracts - cash flow hedges (GWh) 2015 1 59 - -

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $204 million as at March 31, 2015 (December 31, 2014 - $192 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.

BUSINESS RISK MANAGEMENT

Year-to-date 2015, the business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2014 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable.

Regulatory Risk: For further information, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.

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 that 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.

Capital Project Budget Overrun, Completion and Financing Risk in the Corporation's Non-Regulated Business: As a result of the completion of the Waneta Expansion on April 1, 2015, ahead of schedule and on budget, the risks associated with this capital project are no longer applicable.

Capital Resources and Liquidity Risk - Credit Ratings: In February 2015 Moody's Investor Service upgraded the debt credit ratings of UNS Energy to 'Baa1' from 'Baa2' and TEP, UNS Electric and UNS Gas to 'A3' from 'Baa1'.

Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at March 31, 2015, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $2,596 million, up $226 million or 10% from $2,370 million as at December 31, 2014.

Labour Relations: The collective agreement between FortisBC Energy and Canadian Office and Professional Employees Union ("COPE"), representing employees in specified occupations in the areas of administration and operations support, expired on March 31, 2015. Negotiations for a renewed collective agreement commenced in February 2015. FortisBC Energy and COPE had agreed to mediation at the Labour Relations Board, which was scheduled for April 2015. COPE left mediation and no future dates have been scheduled for bargaining or mediation. In late April 2015 the Company and COPE met with the Labour Relations Board to mediate essential services levels and on the same day COPE issued 72-hour strike notice.

The two collective agreements between Newfoundland Power and International Brotherhood of Electrical Workers ("IBEW") expired on September 30, 2014. The Company and IBEW reached tentative agreements in December 2014. One agreement was ratified in March 2015 and the second was not accepted. Conciliation proceedings in respect of the outstanding collective agreement began in April 2015.

CHANGES IN ACCOUNTING POLICIES

The new US GAAP accounting pronouncements that are applicable to, and were adopted by, Fortis, effective January 1, 2015, are described as follows.

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
Effective January 1, 2015, the Corporation adopted Accounting Standards Update ("ASU") No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The above-noted ASU was applied prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three months ended March 31, 2015.

FUTURE ACCOUNTING PRONOUNCEMENTS

Revenue from Contracts with Customers

In May 2014 the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, Revenue from Contracts with Customers. The amendments in this update create Accounting Standards Codification ("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. In April 2015 FASB issued an Exposure Draft of a proposed ASU that would delay by one year the effective date of its new revenue recognition standard and allow early adoption as of the original effective date. 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. Early adoption is permitted. 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.

Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items

In January 2015 FASB issued ASU No. 2015-01, Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. The amendments in this update are part of FASB's initiative to reduce complexity in accounting standards by eliminating the concept of extraordinary items. This update is effective for annual and interim periods beginning on or after December 15, 2015 and may be applied prospectively or retrospectively. Early adoption is permitted. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.

Amendments to the Consolidation Analysis

In February 2015 FASB issued ASU No. 2015-02, Amendments to the Consolidation Analysis. The amendments in this update are to respond to stakeholders' concerns about the current accounting for consolidation of certain legal entities. The amendments eliminate the voting interest consolidation model for limited partnerships and similar entities and makes changes to the variable interest entity consolidation model. This update is effective for annual and interim periods beginning on or after December 15, 2015 and may be applied using a modified retrospective approach or retrospectively. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015 FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update would require that debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. This update is effective for annual and interim periods beginning on or after December 15, 2015 and should be applied on a retrospective basis. Early adoption is permitted. The adoption of this update will result in the reclassification of debt issuance costs from long-term other assets to long-term debt on the Corporation's consolidated balance sheet. As at March 31, 2015, debt issuance costs included in long-term other assets were approximately $70 million (December 31, 2014 - $67 million).

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation's interim unaudited 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. Additionally, certain estimates and judgments 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. 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. 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.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2015 from those disclosed in the 2014 Annual MD&A, with exception of depreciation and amortization at FortisAlberta as discussed below.

Depreciation and Amortization: Effective January 1, 2015, FortisAlberta's depreciation and amortization rates were changed as a result of an update to its last depreciation study, which was completed as of December 31, 2010. As a result, depreciation and amortization expense decreased by approximately $1.5 million for the three months ended March 31, 2015.

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 the Federal Energy Regulatory Commission ("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 February 2015 FERC issued an order denying the third-party owners complaint. In March 2015 the third-party owners filed a request for rehearing in the FERC Action. In April 2015 TEP filed an answer in response to the request for rehearing, and FERC has not yet provided a ruling on this request.

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; TEP failed to comply with their instructions to specify the level of fuel and fuel handling services; TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases; TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action; and 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 February 2015 TEP filed a motion to dismiss in the New York Action that requests that the Court dismiss various counts of the complaint. In March 2015 the third-party owners filed a first amended complaint which includes all the counts that were in the original complaint except those alleging that TEP refused to comply with the third-party owners' instructions to schedule power and energy and to specify the level of fuel and fuel handling services, which have been dropped. The amended complaint also includes new counts alleging that: TEP has failed to pay the third-party owners approximately US$71 million in liquidated damages they allege they are owed, as discussed below; TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired; TEP has converted the third-party owners' water rights and TEP has been unjustly enriched as a result; and TEP has breached the lease transaction documents by refusing to pay certain of the third-party owners' claimed expenses. In April 2015 TEP filed a motion to compel arbitration and to dismiss or stay certain counts of the amended complaint in the New York Action.

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 January 2015 Wilmington Trust Company sent a second notice repeating the allegations in the December 2014 notice. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.

In April 2015 TEP filed a demand for arbitration with the American Arbitration Association seeking an award of the third-party owners' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. As at March 31, 2015, TEP billed the third-party owners approximately US$6 million for their pro-rata share of Springerville Unit 1 operating expenses and less than US$1 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015.

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 relief sought for these claims, the Corporation 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$52 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The mine reclamation liability recorded as at March 31, 2015 was US$23 million (December 31, 2014 - 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 Manufactured Gas Plant ("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 New York State Department of Environmental Conservation ("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 March 31, 2015, an obligation of US$106 million was recognized in respect of MGP remediation and, based upon cost model analysis completed in 2014, 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 New York State Public Service Commission, 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 March 31, 2015. 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 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.

SUMMARY OF QUARTERLY RESULTS

The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2013 through March 31, 2015. 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
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
March 31, 2015 1,915 198 0.72 0.71
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

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 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.

March 2015/March 2014: Net earnings attributable to common equity shareholders were $198 million, or $0.72 per common share, for the first quarter of 2015 compared to earnings of $143 million, or $0.67 per common share, for the first quarter of 2014. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.

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. 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.

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 FortisBC Energy and FortisBC Electric in 2013; (iii) electricity sales growth at the Caribbean Regulated Electric Utilities; and (iv) increased non-regulated hydroelectric generation in Belize.

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. An announcement on the outcome of the strategic review is expected to be made in the second quarter of 2015. Fortis Properties comprises approximately 3% of the Corporation's total assets.

Following a decade of growth driven mainly by acquisitions, Fortis has entered a period of significant organic growth. The Corporation's enterprise-wide capital program is expected to surpass $2 billion in 2015. Over the five-year period through 2019, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase midyear rate base by approximately 38% from $14 billion in 2014 to more than $19 billion in 2019 and produce a five-year compound annual growth rate ("CAGR") of approximately 6.5%. Two new natural gas infrastructure investments in British Columbia that Fortis is pursuing - Tilbury 1B and the pipeline expansion to Woodfibre LNG - could increase the five-year CAGR in rate base to 7.5%.

Looking out over the five-year horizon, the Corporation expects this capital investment to support continuing growth in earnings and dividends.

OUTSTANDING SHARE DATA

As at May 4, 2015, the Corporation had issued and outstanding approximately 277.5 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 or not 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 May 4, 2015 is as follows.

Conversion of Securities into Common Shares(Unaudited)
As at May 4, 2015 Number of
Common Shares
Security (millions)
Stock Options 4.9
First Preference Shares, Series E 5.4
Total 10.3

Additional information, including the Fortis 2014 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.

FORTIS INC.

Interim Consolidated Financial Statements

For the three months ended March 31, 2015 and 2014

(Unaudited)

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

Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
March 31, December 31,
2015 2014
ASSETS
Current assets
Cash and cash equivalents$299 $230
Accounts receivable and other current assets 945 900
Prepaid expenses 65 59
Inventories 272 321
Regulatory assets (Note 5) 279 295
Assets held for sale (Note 6) 38 -
Deferred income taxes 170 158
2,068 1,963
Other assets 361 337
Regulatory assets (Note 5) 2,362 2,230
Deferred income taxes 70 62
Utility capital assets 18,015 17,152
Non-utility capital assets 660 664
Intangible assets 508 488
Goodwill 3,942 3,732
$27,986 $26,628
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 17)$362 $330
Accounts payable and other current liabilities 1,437 1,440
Regulatory liabilities (Note 5) 204 192
Current installments of long-term debt 513 525
Current installments of capital lease and finance obligations 173 208
Liabilities associated with assets held for sale (Note 6) 6 -
Deferred income taxes 15 9
2,710 2,704
Other liabilities 1,203 1,141
Regulatory liabilities (Note 5) 1,440 1,363
Deferred income taxes 1,923 1,837
Long-term debt 10,637 9,976
Capital lease and finance obligations 496 495
18,409 17,516
Shareholders' equity
Common shares (1)(Note 7) 5,719 5,667
Preference shares 1,820 1,820
Additional paid-in capital 14 15
Accumulated other comprehensive income 426 129
Retained earnings 1,164 1,060
9,143 8,691
Non-controlling interests 434 421
9,577 9,112
$27,986 $26,628
(1)No par value. Unlimited authorized shares; 277.5 million and 276.0 million issued and outstanding as at March 31, 2015 and December 31, 2014, respectively

Commitments and Contingencies (Notes 18 and 20, respectively)

See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars, except per share amounts)
Quarter Ended
2015 2014
Revenue$1,915 $1,455
Expenses
Energy supply costs 833 679
Operating 473 319
Depreciation and amortization 215 148
1,521 1,146
Operating income 394 309
Other income (expenses), net (Note 10) 17 7
Finance charges (Note 11) 134 123
Earnings before income taxes and discontinued operations 277 193
Income tax expense (Note 12) 57 39
Earnings from continuing operations 220 154
Earnings from discontinued operations, net of tax (Note 13) - 5
Net earnings$220 $159
Net earnings attributable to:
Non-controlling interests$2 $2
Preference equity shareholders 20 14
Common equity shareholders 198 143
$220 $159
Earnings per common share from continuing operations (Note 14)
Basic$0.72 $0.65
Diluted$0.71 $0.64
Earnings per common share (Note 14)
Basic$0.72 $0.67
Diluted$0.71 $0.66
See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2015 2014
Net earnings$220 $159
Other comprehensive income
Unrealized foreign currency translation gains, net of hedging activities and tax 298 30
Unrealized employee future benefits (losses) gains, net of tax (1) 1
297 31
Comprehensive income$517 $190
Comprehensive income attributable to:
Non-controlling interests$2 $2
Preference equity shareholders 20 14
Common equity shareholders 495 174
$517 $190
See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2015 2014
Operating activities
Net earnings$220 $159
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation - capital assets 193 130
Amortization - intangible assets 16 13
Amortization - other 6 5
Deferred income tax recovery (9) (7)
Accrued employee future benefits 3 (9)
Equity component of allowance for funds used during construction (Note 10) (4) (2)
Other (4) 1
Change in long-term regulatory assets and liabilities (48) 30
Change in non-cash operating working capital (Note 15) 77 (55)
450 265
Investing activities
Change in other assets and other liabilities (15) 3
Capital expenditures - utility capital assets (530) (221)
Capital expenditures - non-utility capital assets (4) (9)
Capital expenditures - intangible assets (20) (7)
Contributions in aid of construction 15 18
Proceeds on sale of assets (Note 13) 1 106
(553) (110)
Financing activities
Change in short-term borrowings - (98)
Proceeds from convertible debentures, net of issue costs - 561
Proceeds from long-term debt, net of issue costs 407 33
Repayments of long-term debt and capital lease and finance obligations (170) (11)
Net repayments under committed credit facilities (19) (145)
Advances from non-controlling interests 5 13
Issue of common shares, net of costs and dividends reinvested 17 11
Dividends
Common shares, net of dividends reinvested (60) (47)
Preference shares (20) (14)
Subsidiary dividends paid to non-controlling interests (4) (2)
156 301
Effect of exchange rate changes on cash and cash equivalents 19 -
Change in cash and cash equivalents 72 456
Less cash associated with assets held for sale (Note 6) (3) -
Cash and cash equivalents, beginning of period 230 72
Cash and cash equivalents, end of period$299 $528
Supplementary Information to Consolidated Statements of Cash Flows (Note 15)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Accumulated
Additional Other Non-
Common PreferencePaid-in Comprehensive Retained Controlling Total
Shares SharesCapital Income (Loss) Earnings Interests Equity
(Note 7)
As at January 1, 2015$5,667 $1,820$15 $129 $1,060 $421 $9,112
Net earnings - - - - 218 2 220
Other comprehensive income - - - 297 - - 297
Common share issues 52 - (2) - - - 50
Stock-based compensation - - 1 - - - 1
Advances from non-controlling interests - - - - - 5 5
Foreign currency translation impacts - - - - - 10 10
Subsidiary dividends paid to non-controlling interests - - - - - (4) (4)
Dividends declared on common shares ($0.34 per share) - - - - (94) - (94)
Dividends declared on preference shares - - - - (20) - (20)
As at March 31, 2015$5,719 $1,820$14 $426 $1,164 $434 $9,577
As at January 1, 2014$3,783 $1,229$17 $(72)$1,044 $375 $6,376
Net earnings - - - - 157 2 159
Other comprehensive income - - - 31 - - 31
Common share issues 33 - (1) - - - 32
Stock-based compensation - - 1 - - - 1
Advances from non-controlling interests - - - - - 13 13
Foreign currency translation impacts - - - - - 5 5
Subsidiary dividends paid to non-controlling interests - - - - - (2) (2)
Dividends declared on common shares ($0.32 per share) - - - - (69) - (69)
Dividends declared on preference shares - - - - (14) - (14)
As at March 31, 2014$3,816 $1,229$17 $(41)$1,118 $393 $6,532
See accompanying Notes to Interim Consolidated Financial Statements

FORTIS INC.

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

For the three months ended March 31, 2015 and 2014 (unless otherwise stated)

(Unaudited)

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 outlines each of the Corporation's reportable segments and is consistent with the basis of segmentation as disclosed in the Corporation's 2014 annual audited consolidated financial statements.

REGULATED UTILITIES

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

  1. Regulated Electric & Gas Utilities - United States: Comprised of UNS Energy, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. and UNS Gas, Inc., acquired by Fortis in August 2014, and Central Hudson Gas & Electric Corporation ("Central Hudson").
  1. Regulated Gas Utility - Canadian: Primarily includes FortisBC Energy Inc. ("FEI") and, prior to December 31, 2014, FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"). On December 31, 2014, FEI, FEVI and FEWI were amalgamated and FEI is the resulting Company.
  1. Regulated Electric Utilities - Canadian: Comprised of FortisAlberta, FortisBC Electric, and Eastern Canadian Electric Utilities (Newfoundland Power, Maritime Electric and FortisOntario). FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and Power Company, Limited and Algoma Power Inc.
  1. Regulated Electric Utilities - Caribbean: Comprised of Caribbean Utilities, in which Fortis holds an approximate 60% controlling interest, and two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos").

NON-REGULATED - FORTIS GENERATION

Fortis Generation includes the financial results of non-regulated generation assets in Belize, British Columbia, Upstate New York and Ontario. In March 2015 the Corporation entered into an agreement to sell its non-regulated generation assets in Upstate New York and Ontario. As a result, the associated assets and liabilities have been classified as held for sale on the consolidated balance sheet as at March 31, 2015 (Note 6).

NON-REGULATED - NON-UTILITY

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. An announcement on the outcome of the strategic review is expected to be made in the second quarter of 2015.

Griffith Energy Services, Inc. ("Griffith") was sold in March 2014 (Note 13).

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. 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. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") for interim financial statements. As a result, these interim consolidated financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation's 2014 annual audited consolidated financial statements. In management's opinion, the interim consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the consolidated financial position of the Corporation.

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. As a result of natural gas consumption patterns, most of the annual earnings of FortisBC Energy 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 cooling requirements of retail customers. Given the diversified group of companies, seasonality may vary.

The preparation of the 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.

Additionally, certain estimates and judgments 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. 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. 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.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2015, except as follows.

Effective January 1, 2015, FortisAlberta's depreciation and amortization rates were changed as a result of an update to its last depreciation study, which was completed as of December 31, 2010. As a result, depreciation and amortization expense decreased by approximately $1.5 million for the three months ended March 31, 2015.

An evaluation of subsequent events through May 4, 2015, the date these interim consolidated financial statements were approved by the Audit Committee of the Board of Directors, was completed to determine whether circumstances warranted recognition and disclosure of events or transactions in the interim consolidated financial statements as at March 31, 2015.

All amounts are presented in Canadian dollars unless otherwise stated.

These interim consolidated financial statements are comprised of the accounts of Fortis and its wholly owned subsidiaries and controlling ownership interests. All significant intercompany balances and transactions have been eliminated on consolidation.

These interim consolidated financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2014 annual audited consolidated financial statements, except as described below.

New Accounting Policies

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
Effective January 1, 2015, the Corporation adopted Accounting Standards Update ("ASU") No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The above-noted ASU was applied prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three months ended March 31, 2015.

3. FUTURE ACCOUNTING PRONOUNCEMENTS

Revenue from Contracts with Customers

In May 2014 the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, Revenue from Contracts with Customers. The amendments in this update create Accounting Standards Codification ("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. In April 2015 FASB issued an Exposure Draft of a proposed ASU that would delay by one year the effective date of its new revenue recognition standard and allow early adoption as of the original effective date. 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. Early adoption is permitted. 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.

Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items

In January 2015 FASB issued ASU No. 2015-01, Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. The amendments in this update are part of FASB's initiative to reduce complexity in accounting standards by eliminating the concept of extraordinary items. This update is effective for annual and interim periods beginning on or after December 15, 2015 and may be applied prospectively or retrospectively. Early adoption is permitted. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.

Amendments to the Consolidation Analysis

In February 2015 FASB issued ASU No. 2015-02, Amendments to the Consolidation Analysis. The amendments in this update are to respond to stakeholders' concerns about the current accounting for consolidation of certain legal entities. The amendments eliminate the voting interest consolidation model for limited partnerships and similar entities and makes changes to the variable interest entity consolidation model. This update is effective for annual and interim periods beginning on or after December 15, 2015 and may be applied using a modified retrospective approach or retrospectively. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015 FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update would require that debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. This update is effective for annual and interim periods beginning on or after December 15, 2015 and should be applied on a retrospective basis. Early adoption is permitted. The adoption of this update will result in the reclassification of debt issuance costs from long-term other assets to long-term debt on the Corporation's consolidated balance sheet. As at March 31, 2015, debt issuance costs included in long-term other assets were approximately $70 million (December 31, 2014 - $67 million).

4. SEGMENTED INFORMATION

Information by reportable segment is as follows:

REGULATEDNON-REGULATED
United StatesCanada
Quarter EndedElectric & Gas GasElectric Inter-
March 31, 2015UNSCentral FortisBCFortisFortisBCEastern CaribbeanFortisNon- Corporate segment
($ millions)EnergyHudsonTotalEnergyAlbertaElectricCanadianTotalElectricGenerationUtility and Other eliminations Total
Revenue435292727488146963221,05278753 7 (9)1,915
Energy supply costs188134322217-2522446645-- - - 833
Operating expenses1351002357046223917712344 5 (3)473
Depreciation and amortization601474484114201231116 - - 215
Operating income5244961535935392861033 2 (6)394
Other income (expenses), net12331--41-- 9 - 17
Finance charges2393234191014774-6 21 (6)134
Income tax expense (recovery)10152534-2642--(1)(9)- 57
Net earnings (loss)2022428841231917173(2)(1)- 220
Non-controlling interests--------2-- - - 2
Preference share dividends----------- 20 - 20
Net earnings (loss) attributable to common equity shareholders2022428841231917153(2)(21)- 198
Goodwill1,7505712,321913227235671,442179-- - - 3,942
Identifiable assets6,4332,4318,8644,8863,3341,8302,20512,2558901,035687 753 (440)24,044
Total assets8,1833,00211,1855,7993,5612,0652,27213,6971,0691,035687 753 (440)27,986
Gross capital expenditures19333226118106323529121114 1 - 554
Quarter Ended
March 31, 2014
($ millions)
Revenue-272272513126953121,046741154 7 (9)1,455
Energy supply costs-137137251-27218496451- - - 679
Operating expenses-8989714322381749242 5 (2)319
Depreciation and amortization-111146411420121916 - - 148
Operating income-35351454232362551176 2 (7)309
Other income (expenses), net-2212--3--- 2 - 7
Finance charges-9935191014784-6 33 (7)123
Income tax expense (recovery)-101032-4541-1- (13)- 39
Net earnings (loss) from continuing operations-18187925181713976- (16)- 154
Earnings from discontinued operations, net of tax----------5 - - 5
Net earnings (loss)-181879251817139765 (16)- 159
Non-controlling interests--------2-- - - 2
Preference share dividends----------- 14 - 14
Net earnings (loss) attributable to common equity shareholders-181879251817139565 (30)- 143
Goodwill-499499913227235671,442156-- - - 2,097
Identifiable assets-1,9021,9024,6313,0841,7762,11611,607724909675 1,290 (614)16,493
Total assets-2,4012,4015,5443,3112,0112,18313,049880909675 1,290 (614)18,590
Gross capital expenditures-21215179152517013249 - - 237

Related party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant related party inter-segment transactions for the three months ended March 31, 2015 and 2014 were as follows:

Significant Related Party Inter-Segment TransactionsQuarter Ended
March 31
($ millions)20152014
Sales from Eastern Canadian Electric Utilities to Non-Utility22
Inter-segment finance charges on lending from:
Corporate to Regulated Electric Utilities - Caribbean-1
Corporate to Non-Utility65
The significant related party inter-segment asset balances were as follows:
As at March 31
($ millions)20152014
Inter-segment lending from:
Fortis Generation to Eastern Canadian Electric Utilities2020
Corporate to Regulated Gas Utility - Canadian-18
Corporate to Regulated Electric Utilities - Canadian-86
Corporate to Regulated Electric Utilities - Caribbean-100
Corporate to Non-Utility410378
Other inter-segment assets1012
Total inter-segment eliminations440614

5. REGULATORY ASSETS AND LIABILITIES

A summary of the Corporation's regulatory assets and liabilities is provided below. For a detailed description of the nature of the Corporation's regulatory assets and liabilities, refer to Note 7 to the Corporation's 2014 annual audited consolidated financial statements.

As at
March 31, December 31,
($ millions)2015 2014
Regulatory assets
Deferred income taxes963 942
Employee future benefits678 680
Manufactured gas plant ("MGP") site remediation deferral (Note 20)134 123
Deferred energy management costs118 111
Rate stabilization accounts112 119
Deferred lease costs108 101
Derivative instruments (Note 16)89 69
Deferred operating overhead costs57 54
Deferred net losses on disposal of utility capital assets and intangible assets36 37
Final mine reclamation and retiree health care costs34 34
Property tax deferrals32 29
Springerville Unit 1 unamortized leasehold improvements (1)32 -
Natural gas for transportation incentives24 24
Income taxes recoverable on other post-employment benefit ("OPEB") plans24 24
Carrying charges - employee future benefits22 20
Other regulatory assets178 158
Total regulatory assets2,641 2,525
Less: current portion(279)(295)
Long-term regulatory assets2,362 2,230
(1) Upon expiration of TEP's Springerville Unit 1 capital lease in January 2015, unamortized leasehold improvements were reclassified from utility capital assets to regulatory assets. The leasehold improvements represent investments made by TEP through the end of the lease term to ensure Springerville facilities continued providing safe, reliable service to TEP's customers. In its 2013 rate case, TEP received regulatory approval to amortize the leasehold improvements over a 10-year period. TEP continues to own an undivided 49.5% joint interest in Springerville Unit 1.
As at
March 31, December 31,
($ millions)2015 2014
Regulatory liabilities
Non-asset retirement obligation removal cost provision991 951
Rate stabilization accounts148 142
Deferred income taxes119 110
Employee future benefits65 58
Customer and community benefits obligation54 55
Alberta Electric System Operator charges deferral53 49
Renewable energy surcharge43 44
Carrying charges - employee future benefits29 24
Other regulatory liabilities142 122
Total regulatory liabilities1,644 1,555
Less: current portion(204)(192)
Long-term regulatory liabilities1,440 1,363

6. ASSETS HELD FOR SALE

In March 2015 the Corporation entered into an agreement to sell its non-regulated generation assets in Upstate New York and Ontario. The sale of the generation assets in Upstate New York and Ontario is expected to close in the second quarter of 2015 and the second half of 2015, respectively. As a result, the associated assets and liabilities have been classified as held for sale on the consolidated balance sheet as at March 31, 2015. For the three months ended March 31, 2015, a loss before taxes of less than $1 million was recognized, compared to earnings before taxes of $2 million for the three months ended March 31, 2014, in the Non-Regulated-Fortis Generation segment associated with these assets held for sale. A gain on the sale is expected to be recognized in earnings at the time of closing.

The table below details the assets and liabilities held for sale.

As at
March 31,
($ millions)2015
ASSETS
Current assets
Cash and cash equivalents3
Accounts receivable and other current assets1
4
Utility capital assets34
Assets held for sale38
LIABILITIES
Current liabilities
Accounts payable and other current liabilities1
1
Deferred income taxes5
Liabilities associated with assets held for sale6

7. COMMON SHARES

Common shares issued during the period were as follows:

Quarter Ended
March 31, 2015
Number of
SharesAmount
(in thousands)($ millions)
Balance, beginning of period275,9975,667
Dividend Reinvestment Plan89634
Consumer Share Purchase Plan7-
Employee Share Purchase Plan1406
Stock Option Plans42912
Conversion of convertible debentures (Note 11)10-
Balance, end of period277,4795,719

8. STOCK-BASED COMPENSATION PLANS

Stock Options

In March 2015 the Corporation granted 667,244 options to purchase common shares under its 2012 Stock Option Plan ("2012 Plan") at the five-day volume weighted average trading price immediately preceding the date of grant of $39.25. The options granted under the 2012 Plan are exercisable for a period not to exceed ten years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four-year period on each anniversary of the date of grant. Directors are not eligible to receive grants of options under the 2012 Plan.

The fair value of each option granted was $2.46 per option. The fair value was estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:

Dividend yield (%)3.6
Expected volatility (%)14.6
Risk-free interest rate (%)0.9
Weighted average expected life (years)5.5

Directors' Deferred Share Unit Plan

In January 2015, 6,394 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors, representing the first quarter equity component of the Directors' annual compensation and, where opted, their first quarter component of annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors.

Share Unit Plans

The Corporation has the following share unit plans that represent a component of long-term compensation awarded to senior management of the Corporation and its subsidiaries: (i) Performance Share Unit ("PSU") Plans, including the 2013 PSU Plan and 2015 PSU Plan; and (ii) the 2015 Restricted Share Unit ("RSU") Plan. In addition, certain subsidiaries of the Corporation have also adopted similar share unit plans that are modelled after the Corporation's plans. Each share unit has an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting period, at which time a cash payment may be made as determined by the Human Resources Committee of the respective Board of Directors. The share unit plans differ in payout criteria, with the PSU plans having certain performance criteria and the RSU plan subject only to the vesting period. Each unit is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors.

In March 2015 a total of 317,700 share units were granted to senior management of the Corporation and its subsidiaries.

In January 2015, 68,759 PSUs, were paid out to the former Chief Executive Officer ("CEO") of the Corporation at $38.90 per PSU, for a total of approximately $3 million. The payout was made in respect of the PSU grant made in March 2012 and the former CEO satisfying the payment requirements, as determined by the Human Resources Committee of the Board of Directors of Fortis.

For the three months ended March 31, 2015, stock-based compensation expense of approximately $4 million was recognized ($2 million for the three months ended March 31, 2014).

9. EMPLOYEE FUTURE BENEFITS

The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans, for employees. The Corporation and certain subsidiaries also offer OPEB plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following table.

Quarter Ended March 31
Defined Benefit
Pension Plans OPEB Plans
($ millions)2015 2014 2015 2014
Components of net benefit cost:
Service costs17 10 4 3
Interest costs27 21 6 4
Expected return on plan assets(34)(24)(3)(2)
Amortization of actuarial losses14 7 1 2
Amortization of past service credits- - (3)(2)
Regulatory adjustments- 2 2 2
Net benefit cost24 16 7 7

For the three months ended March 31, 2015, the Corporation expensed $8 million ($5 million for the three months ended March 31, 2014) related to defined contribution pension plans.

10. OTHER INCOME (EXPENSES), NET

Quarter Ended
March 31
($ millions)20152014
Equity component of allowance for funds used during construction ("AFUDC")42
Net foreign exchange gain94
Interest income34
Other income (expenses), net1(1)
Acquisition-related expenses-(2)
177

The net foreign exchange gain relates to the translation into Canadian dollars of the Corporation's US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity Limited ("Belize Electricity") (Notes 17 and 19).

The acquisition-related expenses were associated with the acquisition of UNS Energy in August 2014.

11. FINANCE CHARGES

Quarter Ended
March 31
($ millions)20152014
Interest-Long-term debt and capital lease and finance obligations140111
-Convertible debentures-16
-Short-term borrowings32
Debt component of AFUDC(9)(6)
134123

In January 2014 Fortis completed the sale of $1.8 billion aggregate principal amount of 4% convertible debentures to finance a portion of the acquisition of UNS Energy. 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 with the remaining final installment of $666 paid in October 2014. Following receipt of the final installment, substantially all of the convertible debentures were converted into approximately 58.2 million common shares of Fortis.

12. INCOME TAXES

Income taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory income tax rate to earnings before income taxes. The following is a reconciliation of consolidated statutory income taxes to consolidated effective income taxes.

Quarter Ended
March 31
($ millions, except as noted)2015 2014
Combined Canadian federal and provincial statutory income tax rate29.0%29.0%
Statutory income tax rate applied to earnings before income taxes and discontinued operations80 56
Difference in Canadian provincial statutory rates applicable to subsidiaries in different Canadian jurisdictions(5)(5)
Difference between Canadian statutory rate and rates applicable to foreign subsidiaries2 (2)
Items capitalized for accounting purposes but expensed for income tax purposes(19)(13)
Other(1)3
Income tax expense57 39
Effective income tax rate20.6%20.2%

13. DISCONTINUED OPERATIONS

In March 2014 Griffith was sold for proceeds of approximately $105 million (US$95 million). The results of operations to the date of sale are presented as discontinued operations on the consolidated statements of earnings for the three months ended March 31, 2014. Earnings from discontinued operations for the three months ended March 31, 2014 were $8 million, or $5 million after tax.

14. EARNINGS PER COMMON SHARE

The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities.

EPS was as follows:

Quarter ended March 31, 2015
Weighted
Net Earnings to Common ShareholdersAverageEPS
ContinuingDiscontinued Number of
OperationsOperationsTotalSharesContinuingDiscontinued
($ millions)($ millions)($ millions)(millions)OperationsOperationsTotal
Basic EPS198-198276.7$0.72$-$0.72
Effect of potential dilutive securities:
Stock Options---1.0
Preference Shares2-25.4
Diluted EPS200-200283.1$0.71$-$0.71
Quarter ended March 31, 2014
Weighted
Net Earnings to Common ShareholdersAverageEPS
ContinuingDiscontinued Number of
OperationsOperationsTotalSharesContinuingDiscontinued
($ millions)($ millions)($ millions)(millions)OperationsOperationsTotal
Basic EPS1385143213.6$0.65$0.02$0.67
Effect of potential dilutive securities:
Stock Options---0.4
Preference Shares2-26.9
Diluted EPS1405145220.9$0.64$0.02$0.66

15. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

Quarter Ended
March 31
($ millions)2015 2014
Change in non-cash operating working capital:
Accounts receivable and other current assets(24)(145)
Prepaid expenses(2)2
Regulatory assets - current portion39 (30)
Inventories60 70
Accounts payable and other current liabilities(10)53
Regulatory liabilities - current portion14 (5)
77 (55)
Non-cash investing and financing activities:
Common share dividends reinvested34 22
Additions to utility capital assets, non-utility capital assets and intangible assets included in current liabilities and long term other liabilities196 79
Contributions in aid of construction included in current assets5 9
Exercise of stock options into common shares2 1

16. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS

Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value.

The three levels of the fair value hierarchy are defined as follows:

Level 1: Fair value determined using unadjusted quoted prices in active markets;

Level 2: Fair value determined using pricing inputs that are observable; and

Level 3: Fair value determined using unobservable inputs only when relevant observable inputs are not available.

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.

The following table presents, by level within the fair value hierarchy, the Corporation's assets and liabilities accounted for at fair value on a recurring 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.

As at
Fair valueMarch 31, December 31,
($ millions)hierarchy2015 2014
Assets
Energy contracts subject to regulatory deferral (1) (2)Level 32 3
Energy contracts not subject to regulatory deferral (1) (2)Level 3- 1
Other investments (3)Levels 1/248 36
Total gross assets 50 40
Less: Counterparty netting not offset on the balance sheet (4) (2)(3)
Total net assets 48 37
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (5)Levels 1/2/391 72
Energy contracts not subject to regulatory deferral (1) (2)Level 3- 1
Energy contracts - cash flow hedges (2) (6)Level 31 1
Interest rate swaps - cash flow hedges (6)Level 25 5
Total gross liabilities 97 79
Less: Counterparty netting not offset on the balance sheet (4) (2)(3)
Total net liabilities 95 76
(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 $13 million - level 1 and $35 million - level 2 (2014 - $5 million - level 1 and $31 million - level 2)
(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 $48 million - level 2 and $43 million - level 3 (2014 - $2 million - level 1, $35 million - level 2 and $35 million - level 3)
(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 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.

FortisBC Energy holds 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 March 31, 2015, 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 March 31, 2015, unrealized losses of $89 million (December 31, 2014 - $69 million) were recognized in current regulatory assets and no unrealized gains were recognized in regulatory liabilities (Note 5).

Cash Flow Hedges

UNS Energy holds interest rate swaps, expiring through 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 12 months is estimated to be approximately $4 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 March 31, 2015, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

MaturityContracts
Volume(year)(#)201520162017
Energy contracts subject to regulatory deferral:
Electricity swap contracts (gigawatt hours ("GWh"))20179993659219
Electricity power purchase contracts (GWh)2017391,101718145
Gas swap and option contracts (petajoules ("PJ"))201718534266
Gas purchase contract premiums (PJ)20153873--
Energy contracts - cash flow hedges (GWh)2015159--

Financial Instruments Not Carried At Fair Value

The following table discloses the estimated fair value measurements of the Corporation's financial instruments not carried at fair value. The fair values were measured using Level 2 pricing inputs, except as noted. 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:

As at
Asset (Liability)March 31, 2015 December 31, 2014
Carrying Estimated Carrying Estimated
($ millions)Value Fair Value Value Fair Value
Long-term other asset - Belize Electricity (1)125 n/a (2)116 n/a (2)
Long-term debt, including current portion (3)(11,150)(13,339) (10,501)(12,237)
Waneta Expansion Limited Partnership
("Waneta Partnership") promissory note (4)(53)(58) (53)(56)
(1)Included in long-term other assets on the consolidated balance sheet
(2)The Corporation's expropriated investment in Belize Electricity is recognized at book value, including foreign exchange impacts. The actual amount of compensation that the Government of Belize ("GOB") may pay to Fortis is indeterminable at this time (Notes 17 and 19).
(3)The Corporation's $200 million unsecured debentures due 2039 and consolidated borrowings under credit facilities classified as long-term debt of $1,103 million (December 31, 2014 - $1,096 million) are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs.
(4)Included in long-term other liabilities on the consolidated balance sheet

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.

17. FINANCIAL RISK MANAGEMENT

The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.

Credit riskRisk that a counterparty to a financial instrument might fail to meet its obligations under the terms of the financial instrument.
Liquidity riskRisk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments.
Market riskRisk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk.

Credit Risk

For cash equivalents, trade and other accounts receivable, and long-term other receivables, the Corporation's credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.

FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at March 31, 2015, FortisAlberta's gross credit risk exposure was approximately $107 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $1 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.

UNS Energy, Central Hudson and FortisBC Energy may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by only dealing with counterparties that have investment-grade credit ratings. At UNS Energy, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances.

The Corporation is exposed to credit risk associated with the amount and timing of fair value compensation that Fortis is entitled to receive from the GOB as a result of the expropriation of the Corporation's investment in Belize Electricity by the GOB on June 20, 2011. As at March 31, 2015, the Corporation had a long-term other asset of $125 million (December 31, 2014 - $116 million), including foreign exchange impacts, recognized on the consolidated balance sheet related to its expropriated investment in Belize Electricity (Notes 16 and 19).

Liquidity Risk

The Corporation's consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails 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 consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.

To help mitigate liquidity risk, the Corporation and its regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures and seasonal working capital requirements.

The Corporation's committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from 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. As at March 31, 2015, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $250 million. 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.

As at March 31, 2015, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.8 billion, of which approximately $2.1 billion was unused, including $477 million unused under the Corporation's 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 $3.6 billion of the total credit facilities are committed facilities with maturities ranging from 2015 through 2020.

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

As at
Regulated Corporate March 31, December 31,
($ millions)Utilities Non-Regulatedand Other 2015 2014
Total credit facilities (1)2,169 131,621 3,803 3,854
Credit facilities utilized:
Short-term borrowings (2)(362)-- (362)(330)
Long-term debt (3)(206)-(897)(1,103)(1,096)
Letters of credit outstanding(170)-(34)(204)(192)
Credit facilities unused1,431 13690 2,134 2,236
(1)Total credit facilities exclude a $300 million increase to the Corporation's committed corporate credit facility in March 2015, not syndicated by creditors as at March 31, 2015, as discussed below.
(2)The weighted average interest rate on short-term borrowings was approximately 1.1% as at March 31, 2015 (December 31, 2014 - 1.3%).
(3) As at March 31, 2015, credit facility borrowings classified as long term included $206 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2014 - $257 million). The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 1.9% as at March 31, 2015 (December 31, 2014 - 1.8%).

As at March 31, 2015 and December 31, 2014, 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.

The significant changes in available credit facilities from that disclosed in the Corporation's 2014 annual audited consolidated financial statements are as follows.

In March 2015 the Corporation amended its $1 billion corporate committed credit facility, resulting in an increase in the facility to $1.3 billion and an extension of the maturity date to July 2020 from July 2018. As at March 31, 2015, the additional $300 million was not available for use as syndication by creditors was not finalized.

In March 2015 UNS Energy repaid its US$130 million non-revolving term loan commitment using net proceeds from the issuance of long-term debt.

In April 2015 FortisBC Electric amended its $150 million unsecured committed revolving credit facility to now mature in May 2018.

The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at March 31, 2015, the Corporation's credit ratings were as follows:

Standard & Poor's ("S&P")A- / Stable (long-term corporate and unsecured debt credit rating)
DBRSA (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 reasonable levels of debt at the holding company level. In April 2015 S&P confirmed the Corporation's credit rating with a Stable outlook.

Market Risk

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, Belize Electric Company Limited and FortisUS Energy Corporation is the US dollar.

As at March 31, 2015, the Corporation's corporately issued US$1,496 million (December 31, 2014 - US$1,496 million) long-term debt had been designated as an effective hedge of the Corporation's foreign net investments. As at March 31, 2015, the Corporation had approximately US$2,835 million (December 31, 2014 - US$2,762 million) in foreign net investments remaining to be hedged. 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.

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$1.27 as at March 31, 2015 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 (Notes 16 and 19) 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. The Corporation recognized in earnings a foreign exchange gain of approximately $9 million and $4 million for the three months ended March 31, 2015 and 2014, respectively (Note 10).

Interest Rate Risk

The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk.

Commodity Price Risk

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 price of electricity and natural gas. FortisBC Energy is exposed to commodity price risk associated with changes in the market price of natural gas. The risks have been reduced by entering into derivative contracts that effectively fix the price of natural gas, power and electricity. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates (Note 16).

18. COMMITMENTS

There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2014 annual audited consolidated financial statements, except as follows.

In March 2015 Maritime Electric extended its power purchase agreement with New Brunswick Power from March 2016 to February 2019, increasing the total commitment under this agreement by approximately $172 million as at March 31, 2015.

19. EXPROPRIATED ASSETS

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 Caribbean Court of Justice ("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 to be paid to Fortis could be lower than the book value of the Corporation's expropriated investment in Belize Electricity. The book value was $125 million, including foreign exchange impacts, as at March 31, 2015 (December 31, 2014 - $116 million). 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 $125 million long-term other asset is not deemed impaired as at March 31, 2015. Fortis will continue to assess for impairment each reporting period based on evaluating the outcomes of court proceedings and/or compensation settlement negotiations.

20. 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 the Federal Energy Regulatory Commission ("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 February 2015 FERC issued an order denying the third-party owners complaint. In March 2015 the third-party owners filed a request for rehearing in the FERC Action. In April 2015 TEP filed an answer in response to the request for rehearing, and FERC has not yet provided a ruling on this request.

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; TEP failed to comply with their instructions to specify the level of fuel and fuel handling services; TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases; TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action; and 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 February 2015 TEP filed a motion to dismiss in the New York Action that requests that the Court dismiss various counts of the complaint. In March 2015 the third-party owners filed a first amended complaint which includes all the counts that were in the original complaint except those alleging that TEP refused to comply with the third-party owners' instructions to schedule power and energy and to specify the level of fuel and fuel handling services, which have been dropped. The amended complaint also includes new counts alleging that: TEP has failed to pay the third-party owners approximately US$71 million in liquidated damages they allege they are owed, as discussed below; TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired; TEP has converted the third-party owners' water rights and TEP has been unjustly enriched as a result; and TEP has breached the lease transaction documents by refusing to pay certain of the third-party owners' claimed expenses. In April 2015 TEP filed a motion to compel arbitration and to dismiss or stay certain counts of the amended complaint in the New York Action.

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 January 2015 Wilmington Trust Company sent a second notice repeating the allegations in the December 2014 notice. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.

In April 2015 TEP filed a demand for arbitration with the American Arbitration Association seeking an award of the third-party owners' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. As at March 31, 2015, TEP billed the third-party owners approximately US$6 million for their pro-rata share of Springerville Unit 1 operating expenses and less than US$1 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015.

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 relief sought for these claims, the Corporation 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$52 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The mine reclamation liability recorded as at March 31, 2015 was US$23 million (December 31, 2014 - 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 (Note 5).

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 New York State Department of Environmental Conservation ("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 March 31, 2015, an obligation of US$106 million was recognized in respect of MGP remediation and, based upon cost model analysis completed in 2014, 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 New York State Public Service Commission, 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 (Note 5).

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 March 31, 2015. 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 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.

21. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period presentation. The former "Other Canadian Electric Utilities" segment is now "Eastern Canadian Electric Utilities" and now includes Newfoundland Power, Maritime Electric and FortisOntario.

CORPORATE INFORMATION

Fortis Inc. is a leader in the North American electric and gas utility business, with total assets of approximately $28 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.

The Common Shares; First Preference Shares, Series E; First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M of Fortis are listed on the Toronto Stock Exchange and trade under the ticker symbols FTS, FTS.PR.E, FTS.PR.F, FTS.PR.G, FTS.PR.H, FTS.PR.J, FTS.PR.K, and FTS.PR.M, respectively.

Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.investorcentre.com/fortisinc

Additional information, including the Fortis 2014 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.

Karl W. Smith
Executive Vice President, Chief Financial Officer
Fortis Inc.
709.737.2822

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