Fortis Inc.
TSX : FTS

Fortis Inc.

July 31, 2015 06:30 ET

Fortis Delivers Record Second Quarter Earnings of $244 Million

Sale of Commercial Real Estate and Non-Regulated Generation Assets in New York Complete

$1.2 Billion in Capital Invested in the First Half of 2015

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - July 31, 2015) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) released its second quarter results today. Net earnings attributable to common equity shareholders for the second quarter were $244 million, or $0.88 per common share, compared to $47 million, or $0.22 per common share, for the second quarter of 2014.

"Performance in the second quarter was bolstered by one-time gains associated with the sale of Fortis Properties' commercial real estate assets and non-regulated hydroelectric generation assets in New York," says Barry Perry, President and Chief Executive Officer, Fortis.

In June 2015 the Corporation completed the sale of the commercial real estate assets of Fortis Properties Corporation ("Fortis Properties") for gross proceeds of $430 million and non-regulated generation assets in Upstate New York for gross proceeds of approximately $77 million (US$63 million). In July 2015 the Corporation closed the sale of its non-regulated generation assets in Ontario for gross proceeds of $16 million and signed an agreement with a private investor group for the sale of the hotel assets of Fortis Properties for $365 million. The hotel transaction is subject to typical closing conditions and is expected to be completed in the fall of 2015. As a result of these sale transactions, the Corporation recognized an overall after-tax gain of approximately $123 million, net of expenses. Net proceeds from the sales will be used by the Corporation to repay credit facility borrowings, largely associated with the acquisition of UNS Energy Corporation ("UNS Energy"), and for other general corporate purposes.

"The sale of the commercial real estate and hotel assets, and non-regulated generation assets in New York and Ontario, is consistent with the Corporation's focus on its core utility business," says Perry. "Post closing of the hotel transaction, virtually all of the Corporation's assets will be comprised of regulated utilities and long-term contracted energy infrastructure."

Excluding the impact of the sale transactions and other one-time items, adjusted net earnings attributable to common equity shareholders for the second quarter were $123 million, or $0.44 per common share, an increase of $58 million, or $0.14 per common share, from the second quarter of 2014. Performance was driven by UNS Energy and contribution from the Waneta Expansion hydroelectric generating facility ("Waneta Expansion") in British Columbia. UNS Energy contributed $52 million to earnings for the second quarter and, after considering the common share offering and finance charges associated with the acquisition, had a $0.09 accretive impact on earnings per common share. The Waneta Expansion came online early April 2015 and contributed $12 million to the Corporation's earnings for the second quarter. The Corporation's other regulated utilities also reported strong results.

"Fortis has come through a period of transformative change. Our successful expansion into the U.S. regulated utility market through the acquisitions of Central Hudson and UNS Energy, and the completion of the Waneta Expansion, have positioned Fortis for a strong 2015," says Perry. "Performance for the second quarter demonstrates the benefits of these changes."

The second quarter of 2015 marked the completion of the $900 million, 335-megawatt Waneta Expansion in British Columbia, the Corporation's largest capital project to date, six weeks ahead of schedule and on budget, while maintaining an excellent safety and environmental protection record. Construction continues on FortisBC's Tilbury liquefied natural gas ("LNG") expansion (known as Tilbury 1A), at an estimated total cost of approximately $440 million, which 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 June the New York State Public Service Commission issued a Rate Order for Central Hudson covering a three-year period, with new electricity and gas delivery rates effective July 1, 2015. Central Hudson's approved Rate Order reflects an allowed rate of return on common shareholders' equity of 9.0% and a 48% common equity component of capital structure, and includes continuation of revenue decoupling and earnings sharing mechanisms. It also includes a major storm reserve for electric operations, and provides for continuation of recovery of various operating expenses, including environmental site investigation and remediation costs. The Rate Order includes capital investments of approximately US$490 million during the three-year period targeted at making the electric and gas systems stronger.

Later this year, Tucson Electric Power Company ("TEP"), UNS Energy's largest utility, will file a general rate application requesting new retail rates to be effective January 1, 2017, using June 30, 2015 as a historical test year. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.8 billion.

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 the first half of 2015, the Corporation's regulated utilities raised more than $600 million in long-term debt at attractive interest rates. Net proceeds from the debt offerings were primarily used to repay maturing long-term debt and credit facility borrowings and to finance capital expenditures.

In June 2015 Fortis injected US$180 million of equity into TEP. Proceeds were used to repay credit facility borrowings and the balance will be used to repay upcoming debt maturities. This equity injection fulfilled one of the commitments made by Fortis in order to receive regulatory approval for the acquisition of UNS Energy, and increased TEP's equity thickness to almost 50%, which is comparable with other regulated utilities in Arizona.

"We are more than half way towards our enterprise-wide capital program for the year, with almost $1.2 billion invested in energy infrastructure in the first half of 2015," says Perry. "Our consolidated capital program is expected to surpass $2 billion this year."

Over the five-year period through 2019, the Corporation's capital program is expected to exceed $9 billion. This investment in energy infrastructure is expected to increase midyear rate base by approximately 40% from $14 billion in 2014 to approximately $19.5 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 the Woodfibre LNG site - 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 Second Quarter 2015 Results

A teleconference and webcast will be held on July 31 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 second 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 August 10, 2015. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 63361893.

Interim Management Discussion and Analysis
For the three and six months ended June 30, 2015
Dated July 31, 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 and six months ended June 30, 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 expected sale of the Corporation's hotel assets; 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 the Woodfibre LNG site, 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 expectation that there will be no material change in the Corporation's consolidated contractual obligations; 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; 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 expected sale of the Corporation's hotel assets; 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 rate of return on common shareholders' equity at the Corporation's regulated utilities; uncertainty related to litigation; and risk associated with the amount of compensation to be paid to Fortis and the ability of the Government of Belize ("GOB") to pay compensation owing to Fortis for its investment in Belize Electricity Limited that was expropriated by the GOB.

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 serve more than 3 million customers across Canada and in the United States and the Caribbean. Fortis also owns long-term contracted hydroelectric generation assets in British Columbia and Belize.

Year-to-date June 30, 2015, the Corporation's electricity distribution systems met a combined peak demand of 9,518 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 and six months ended June 30, 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 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

Sale of Commercial Real Estate and Hotel Assets: In June 2015 the Corporation completed the sale of the commercial real estate assets of Fortis Properties Corporation ("Fortis Properties") for gross proceeds of $430 million. As a result of the sale, the Corporation recognized an after-tax gain of approximately $109 million, net of expenses, in the second quarter. As part of the transaction, Fortis subscribed to $35 million in trust units of Slate Office REIT in conjunction with the REIT's public offering. Net proceeds from the sale were used by the Corporation to repay credit facility borrowings in July 2015, the majority of which were used to finance a portion of the acquisition of UNS Energy Corporation ("UNS Energy").

In July 2015 the Corporation signed an agreement with a private investor group for the sale of the hotel assets of Fortis Properties for $365 million. As at June 30, 2015, the associated assets have been classified as held for sale on the Corporation's interim unaudited consolidated balance sheet and, as a result, the Corporation recognized an approximate $13 million after-tax loss, which includes an impairment loss and expenses associated with the pending sale transaction. The hotel transaction is subject to typical closing conditions and is expected to be completed in the fall of 2015. Proceeds from the sale will be used by the Corporation to repay credit facility borrowings and for other general corporate purposes.

The sale of the commercial real estate and hotel assets is consistent with the Corporation's focus on its core utility business. Post closing of the hotel transaction, virtually all of the Corporation's assets will be comprised of regulated utilities and long-term contracted energy infrastructure.

Sale of Non-Regulated Generation Assets in New York and Ontario: In June 2015 the Corporation sold its non-regulated generation assets in Upstate New York for gross proceeds of approximately $77 million (US$63 million). As a result of the sale, the Corporation recognized an after-tax gain of approximately $27 million (US$22 million), net of expenses and foreign exchange impacts, in the second quarter. Net proceeds from the sale were used by the Corporation to partially finance an equity injection into UNS Energy.

In July 2015 the Corporation closed the sale of its non-regulated generation assets in Ontario for gross proceeds of $16 million. As at June 30, 2015, the associated assets have been classified as held for sale on the Corporation's interim unaudited consolidated balance sheet. The sale is not expected to have a material impact on earnings in the third quarter of 2015.

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. The Waneta Expansion contributed $12 million in earnings to the Corporation in the second quarter of 2015. For further information regarding the Waneta Expansion, refer to the "Non-Regulated - Fortis Generation" and "Capital Expenditure Program" sections of this MD&A.

Regulatory Decisions: In March 2015 regulatory decisions were received on FortisAlberta Inc.'s ("FortisAlberta") Capital Tracker Applications and the Generic Cost of Capital ("GCOC") Proceeding in Alberta. As a result of these regulatory decisions, in the first half of 2015, FortisAlberta recognized a positive $9 million capital tracker revenue adjustment associated with 2013 and 2014.

In June 2015 the New York State Public Service Commission ("PSC") issued a Rate Order for Central Hudson covering a three-year period, with new electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson invested approximately US$250 million in energy infrastructure during the two-year delivery rate freeze period ending June 30, 2015. The approved Rate Order reflects an allowed ROE of 9.0% and a 48% common equity component of capital structure and includes continuation of revenue decoupling and earnings sharing mechanisms.

For further details on these regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of profitable growth with the primary measures of performance being earnings per common share and total shareholder return. 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 second quarter and year-to-date periods ended June 30, 2015 and 2014 are provided in the following table.

Consolidated Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions, except for common share data) 2015 2014 Variance 2015 2014 Variance
Revenue 1,538 1,056 482 3,453 2,511 942
Energy Supply Costs 531 403 128 1,364 1,082 282
Operating Expenses 458 307 151 931 626 305
Depreciation and Amortization 220 149 71 435 297 138
Other Income (Expenses), Net 166 (1 ) 167 183 6 177
Finance Charges 141 124 17 275 247 28
Income Tax Expense 76 9 67 133 48 85
Earnings from Continuing Operations 278 63 215 498 217 281
Earnings from Discontinued
Operations, Net of Tax - - - - 5 (5 )
Net Earnings 278 63 215 498 222 276
Net Earnings Attributable to:
Non-Controlling Interests 15 3 12 17 5 12
Preference Equity Shareholders 19 13 6 39 27 12
Common Equity Shareholders 244 47 197 442 190 252
Net Earnings 278 63 215 498 222 276
Earnings per Common Share from
Continuing Operations
Basic ($) 0.88 0.22 0.66 1.59 0.87 0.72
Diluted ($) 0.87 0.22 0.65 1.58 0.86 0.72
Earnings per Common Share
Basic ($) 0.88 0.22 0.66 1.59 0.89 0.70
Diluted ($) 0.87 0.22 0.65 1.58 0.88 0.70
Weighted Average Common Shares
Outstanding (# millions) 277.9 214.8 63.1 277.3 214.2 63.1
Cash Flow from Operating Activities 468 321 147 918 586 332

Revenue

The increase in revenue for the quarter and year to date was driven by the acquisition of UNS Energy in August 2014. Favourable foreign exchange associated with the translation of US dollar-denominated revenue, contribution from the Waneta Expansion and higher revenue at FortisAlberta also contributed to the increase. The increase was partially offset by a decrease in the commodity cost of natural gas charged to customers at FortisBC Energy.

Energy Supply Costs

The increase in energy supply costs for the quarter and year to date 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 a lower commodity cost of natural gas at FortisBC Energy.

Operating Expenses

The increase in operating expenses for the quarter and year to date 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 for the quarter and year to date 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, for the quarter and year to date was primarily due to a gain of approximately $129 million, net of expenses, on the sale of Fortis Properties' commercial real estate assets and a gain of approximately $51 million (US$41 million), net of expenses and foreign exchange impacts, on the sale of generation assets in Upstate New York in June 2015. 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") also contributed to the increase year to date. The increase was partially offset by a loss of approximately $18 million associated with the pending sale of Fortis Properties' hotel assets.

Finance Charges

The increase in finance charges for the quarter and year to date was primarily due to the acquisition of UNS Energy, including interest expense on debt issued to complete the financing of the acquisition, and unfavorable foreign exchange associated with the translation of US-dollar denominated interest expense. The increase was partially offset by lower interest on convertible debentures. Approximately $18 million ($13 million after tax) and $34 million ($24 million after tax) in interest expense for the quarter and year to date, respectively, was recognized in 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 for the quarter and year to date was primarily due to higher earnings before income taxes, driven by the acquisition of UNS Energy and gains on the sale of Fortis Properties' commercial real estate assets and generation assets in Upstate New York.

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)
Periods Ended June 30 Quarter Year-to-Date
($ millions, except for common share data) 2015 2014 Variance 2015 2014 Variance
Net Earnings Attributable to
Common Equity Shareholders 244 47 197 442 190 252
Adjusting Items:
FortisAlberta -
Capital tracker revenue adjustment for 2013 and 2014 1 - 1 (9 ) - (9 )
Non-Regulated - Fortis Generation -
Gain on sale of generation assets (27 ) - (27 ) (27 ) - (27 )
Non-Utility -
Gain on sale of commercial real estate assets (109 ) - (109 ) (109 ) - (109 )
Loss on pending sale of hotel assets 13 - 13 13 - 13
Earnings from discontinued operations - - - - (5 ) 5
Corporate and Other -
Foreign exchange loss (gain) 1 4 (3 ) (8 ) - (8 )
Interest expense on convertible debentures - 13 (13 ) - 24 (24 )
Acquisition-related expenses - 1 (1 ) - 3 (3 )
Adjusted Net Earnings Attributable to
Common Equity Shareholders 123 65 58 302 212 90
Adjusted Basic Earnings Per Common Share ($) 0.44 0.30 0.14 1.09 0.99 0.10

The increase in adjusted net earnings attributable to common equity shareholders for the quarter and year to date was driven by earnings contribution of $52 million and $72 million, respectively, at UNS Energy. Earnings contribution of $12 million for the quarter and year to date from the Waneta Expansion, which represents the Corporation's 51% controlling ownership, also contributed to the increase. Performance for the quarter and year to date was also driven by the Corporation's regulated utilities, including higher capital tracker revenue for 2015, customer growth and a decrease in depreciation and amortization at FortisAlberta; increases at FortisBC Electric, largely due to timing of quarterly earnings compared to the same periods last year, resulting from the impact of regulatory deferral mechanisms; and improved performance at Central Hudson. Earnings at FortisBC Energy were $5 million lower for the quarter and $4 million higher year to date compared to the same periods last year, mainly due to the timing of regulatory flow-through deferral amounts. The increase in earnings for the quarter and year to date was partially offset by higher preference share dividends and finance charges in the Corporate and Other segment associated with the acquisition of UNS Energy in August 2014.

The increase in adjusted earnings per common share for the quarter was driven by $0.09 accretion associated with 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. Performance at the Corporation's regulated utilities, as discussed above, and contribution from the Waneta Expansion also contributed to the increase.

The increase in adjusted earnings per common share year to date was driven by performance at the Corporation's regulated utilities, as discussed above, and contribution from the Waneta Expansion. The increase was partially offset by a $0.03 dilutive impact of the acquisition of UNS Energy, due to the highly seasonal earnings. In 2014 approximately 75% of UNS Energy's earnings were recognized in the second and third quarters.

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2015 2014 Variance 2015 2014 Variance
Regulated Electric & Gas Utilities -
United States
UNS Energy 52 - 52 72 - 72
Central Hudson 10 7 3 32 25 7
62 7 55 104 25 79
Regulated Gas Utility - Canadian
FortisBC Energy 7 12 (5 ) 95 91 4
Regulated Electric Utilities - Canadian
FortisAlberta 31 26 5 72 51 21
FortisBC Electric 11 7 4 34 25 9
Eastern Canadian 15 16 (1 ) 34 33 1
57 49 8 140 109 31
Regulated Electric Utilities - Caribbean 9 8 1 14 13 1
Non-Regulated - Fortis Generation 45 6 39 48 12 36
Non-Regulated - Non-Utility 104 7 97 102 12 90
Corporate and Other (40 ) (42 ) 2 (61 ) (72 ) 11
Net Earnings Attributable to
Common Equity Shareholders 244 47 197 442 190 252

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 Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Average US:CDN Exchange Rate (2) 1.23 1.09 0.14 1.24 1.10 0.14
Electricity Sales (gigawatt hours ("GWh")) 3,981 - 3,981 7,378 - 7,378
Gas Volumes (petajoules ("PJ")) 2 - 2 7 - 7
Revenue ($ millions) 494 - 494 929 - 929
Earnings ($ millions) 52 - 52 72 - 72
(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 quarter were 3,981 gigawatt hours ("GWh") compared to 3,558 GWh for the same period last year and 7,378 GWh for the first half of 2015 compared to 6,757 GWh for the same period last year. The increase was primarily due to higher short-term wholesale sales. The majority of short-term wholesale sales are flowed through to customers and have no impact on earnings. The increase was partially offset by lower retail sales as a result of cooler temperatures, which reduced the use of air conditioning and other cooling equipment.

Gas volumes for the quarter and year to date were comparable with the same periods 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 quarter and year to date was US$402 million and US$752 million, respectively, compared to US$387 million and US$720 million, respectively, for the same periods last year. The increase was primarily due to the flow through to customers of higher purchased power and fuel supply costs, higher wholesale electricity sales and higher transmission revenue. The increase was partially offset by lower retail electricity sales.

Earnings

Earnings for the quarter and year to date were US$42 million and US$58 million, respectively, and were comparable with the same periods last year. The impact of lower retail electricity sales and higher operating expenses was largely offset by higher transmission revenue and a decrease in interest expense due to the expiry of leasing arrangements.

CENTRAL HUDSON

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Average US:CDN Exchange Rate (1) 1.23 1.09 0.14 1.24 1.10 0.14
Electricity Sales (GWh) 1,217 1,169 48 2,632 2,576 56
Gas Volumes (PJ) 5 5 - 15 15 -
Revenue ($ millions) 193 190 3 485 462 23
Earnings ($ millions) 10 7 3 32 25 7
(1) The reporting currency of Central Hudson is the US dollar.

Electricity Sales & Gas Volumes

The increase in electricity sales for the quarter and year to date was due to higher average consumption as a result of warmer temperatures in the second quarter. Gas volumes for the quarter and year to date were comparable with the same periods last year.

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.

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 for the quarter and year to date was primarily due to approximately $20 million and $51 million, respectively, of favourable foreign exchange associated with the translation of US dollar-denominated revenue. The recovery from customers of previously deferred electricity costs, higher gas revenue associated with a new contract in late 2014, as well as energy-efficiency incentives earned during the first half of 2015 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.

Earnings

The increase in earnings for the quarter and year to date was primarily due to approximately $1 million and $4 million, respectively, 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 first half of 2015, as discussed above, also contributed to the increase in earnings. The increase was partially offset by the impact of higher expenses during the two-year rate freeze period post acquisition, which ended on June 30, 2015.

REGULATED GAS UTILITY - CANADIAN

FORTISBC ENERGY (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Gas Volumes (PJ) 36 36 - 98 111 (13 )
Revenue ($ millions) 228 282 (54 ) 716 795 (79 )
Earnings ($ millions) 7 12 (5 ) 95 91 4
(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

Gas volumes for the quarter were comparable with the same period last year. The decrease in gas volumes year to date was primarily due to lower average consumption in the first quarter 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 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 for the quarter was primarily due to a lower 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.

The decrease in revenue year to date was primarily due to a lower commodity cost of natural gas charged to customers and lower gas volumes, partially offset by the timing of regulatory flow-through deferral amounts, as discussed above.

Earnings

The decrease in earnings for the quarter was mainly due to approximately $8 million associated with the timing of regulatory flow-through deferral amounts, as discussed above, and 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 reverted to those of FEI, which are 8.75% and 38.5%, respectively. The decrease was partially offset by lower operating expenses, net of the regulatory earnings sharing mechanism, and a higher equity component of allowance for funds used during construction ("AFUDC").

The increase in earnings year to date was primarily due to approximately $4 million associated with the timing of regulatory flow-through deferral amounts, as discussed above, lower operating expenses, net of the regulatory earnings sharing mechanism, and a higher equity component of AFUDC. The increase was partially offset by the decrease in the allowed ROE and equity component of capital structure as a result of the amalgamation of FEVI and FEWI with FEI, and other timing differences.

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Energy Deliveries (GWh) 4,026 4,091 (65 ) 8,693 8,774 (81 )
Revenue ($ millions) 136 129 7 282 255 27
Earnings ($ millions) 31 26 5 72 51 21

Energy Deliveries

The decrease in energy deliveries for the quarter and year to date was primarily due to lower average consumption by residential and commercial customers due to warmer temperatures and lower deliveries to oil and gas customers as a result of lower rig activity. The decrease was partially offset by growth in the number of customers. The total number of customers increased by approximately 12,000 year over year as at June 30, 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 for the quarter was primarily due to 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%, higher 2015 capital tracker revenue and growth in the number of customers.

The increase in revenue year to date was due to the same factors discussed above for the quarter, combined with a positive $9 million capital tracker revenue adjustment recognized in the first half of 2015 associated with 2013 and 2014, as discussed below, and higher revenue related to flow-through costs to customers.

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 funded by capital tracker revenue throughout the term of the PBR regulation. The $9 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 this MD&A.

Earnings

The increase in earnings for the quarter and year to date was primarily due to rate base growth and associated 2015 capital tracker revenue, growth in the number of customers and a decrease in depreciation and amortization as a result of a technical update to FortisAlberta's last depreciation study. Also contributing to the increase in earnings year to date was capital tracker revenue of approximately $9 million recognized in the first half of 2015 associated with 2013 and 2014, as discussed above.

FORTISBC ELECTRIC (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Electricity Sales (GWh) 699 694 5 1,538 1,601 (63 )
Revenue ($ millions) 80 71 9 176 166 10
Earnings ($ millions) 11 7 4 34 25 9
(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 increase in electricity sales for the quarter was mainly due to higher average consumption as a result of warmer temperatures. The decrease in electricity sales year to date was primarily due to lower average consumption in the first quarter as a result of warmer temperatures.

Revenue

The increase in revenue for the quarter was driven by an increase in base electricity rates, effective January 1, 2015, electricity sales growth, surplus capacity sales and increases associated with regulatory deferral mechanisms.

The increase in revenue year to date was due to the same factors discussed above for the quarter, partially offset by a decrease in electricity sales.

Earnings

The increase in earnings for the quarter and year to date was primarily due to the timing of earnings compared to the same periods last year as a result of the impact of regulatory deferral mechanisms. Also contributing to the increase in earnings year to date was the timing of power purchase costs and rate base growth. The increase in base electricity rates, effective January 1, 2015, was mainly established to recover higher power purchase costs, which commenced in the second quarter of 2015.

EASTERN CANADIAN ELECTRIC UTILITIES (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Electricity Sales (GWh) 1,912 1,928 (16 ) 4,671 4,644 27
Revenue ($ millions) 232 232 - 554 544 10
Earnings ($ millions) 15 16 (1 ) 34 33 1
(1) Comprised of Newfoundland Power Inc., Maritime Electric Company, Limited and FortisOntario Inc. ("FortisOntario"). FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and Power Company, Limited, and Algoma Power Inc.

Electricity Sales

The decrease in electricity sales for the quarter was primarily due to lower average consumption in Ontario and Newfoundland. The decrease was partially offset by customer growth in Newfoundland and higher average consumption on Prince Edward Island, mainly due to an increase in the number of customers using electricity for home heating.

The increase in electricity sales year to date was mainly due to customer growth in Newfoundland and higher average consumption on Prince Edward Island, as discussed above, partially offset by lower average consumption in Ontario.

Revenue

Revenue for the quarter was consistent with the same period last year. The flow through in customer electricity rates of higher energy supply costs at FortisOntario was largely offset by lower electricity sales.

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

Earnings

The decrease in earnings for the quarter was primarily due to $1 million in business development costs in Ontario.

The increase in earnings year to date was primarily due to electricity sales growth and lower operating costs, mainly due to restoration efforts at Newfoundland Power following the loss of energy supply from Newfoundland and Labrador Hydro and related power interruptions in January 2014. The increase was partially offset by $1 million in business development costs in Ontario.

REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Average US:CDN Exchange Rate (2) 1.23 1.09 0.14 1.24 1.10 0.14
Electricity Sales (GWh) 202 197 5 382 377 5
Revenue ($ millions) 74 78 (4 ) 152 152 -
Earnings ($ millions) 9 8 1 14 13 1
(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

The increase in electricity sales for the quarter and year to date was primarily due to growth in the number of customers and warmer temperatures on the Turks and Caicos Islands. Higher average consumption by commercial customers on Grand Cayman also contributed to the increase in electricity sales for the quarter.

Revenue

The decrease in revenue for the quarter was mainly due to the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities, partially offset by approximately $8 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue and electricity sales growth.

Revenue year to date was consistent with the same period last year. The impact of approximately $17 million in favorable foreign exchange associated with the translation of US dollar-denominated revenue and electricity sales growth was offset by the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities.

Earnings

Earnings for the quarter and year to date were comparable with the same periods last year. Favorable foreign exchange associated with the translation of US dollar-denominated earnings and electricity sales growth were partially offset by higher depreciation.

NON-REGULATED - FORTIS GENERATION (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2015 2014 Variance 2015 2014 Variance
Energy Sales (GWh) 492 122 370 552 221 331
Revenue ($ millions) 41 11 30 48 22 26
Earnings ($ millions) 45 6 39 48 12 36
(1) Primarily comprised of hydroelectric generation assets in British Columbia and Belize, with a combined generating capacity of 407 MW. 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. Non-regulated generation assets in Upstate New York and Ontario were sold in June 2015 and July 2015, respectively. For further information, refer to the "Significant Items" section of this MD&A.

Energy Sales

The increase in energy sales for the quarter and year to date was driven by the Waneta Expansion, which commenced production on April 2, 2015 and reported 397 GWh in energy sales for the second quarter. The increase was partially offset by decreased production in Belize, Upstate New York and Ontario, due to lower rainfall and generating units taken out of service for repairs.

Revenue

The increase in revenue for the quarter and year to date was driven by the Waneta Expansion, which recognized $31 million of revenue in the second quarter. The increase was partially offset by decreased production in Belize, Upstate New York and Ontario.

Earnings

The increase in earnings for the quarter and year to date was primarily due to an after-tax gain of approximately $27 million (US$22 million), net of expenses and foreign exchange impacts, on the sale of generation assets in Upstate New York in June 2015. Excluding the gain, earnings for the quarter and year to date increased by $12 million and $9 million, respectively. The increase was driven by earnings contribution of $12 million from the Waneta Expansion, which represents the Corporation's 51% controlling ownership interest. The impact of decreased production in Belize, Upstate New York and Ontario was partially offset by lower business development costs.

NON-REGULATED - NON-UTILITY (1)

Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2015 2014 Variance 2015 2014 Variance
Revenue 65 65 - 118 119 (1 )
Earnings 104 7 97 102 12 90
(1) Comprised of Fortis Properties and Griffith Energy Services, Inc. ("Griffith"). Fortis Properties completed the sale of its commercial real estate assets in June 2015 and signed an agreement for the sale of its hotel assets in July 2015. For further information, refer to the "Significant Items" section of this MD&A. Griffith 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 quarter and year to date was comparable to the same periods last year.

Earnings

The increase in earnings for the quarter and year to date was primarily due to an after-tax gain of approximately $109 million, net of expenses, on the sale of Fortis Properties' commercial real estate assets. The increase was partially offset by an after-tax loss of approximately $13 million associated with the pending sale of Fortis Properties' hotel assets. For further information, refer to the "Significant Items" section of this MD&A. Earnings for the first quarter of 2014 include $5 million associated with Griffith from normal operations to the date of sale in March 2014.

CORPORATE AND OTHER (1)

Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2015 2014 Variance 2015 2014 Variance
Revenue 7 8 (1 ) 14 15 (1 )
Operating Expenses 12 9 3 17 14 3
Depreciation and Amortization 1 1 - 1 1 -
Other Income (Expenses), Net (1 ) (3 ) 2 8 (1 ) 9
Finance Charges 24 35 (11 ) 45 68 (23 )
Income Tax Recovery (10 ) (11 ) 1 (19 ) (24 ) 5
(21 ) (29 ) 8 (22 ) (45 ) 23
Preference Share Dividends 19 13 6 39 27 12
Net Corporate and Other Expenses (40 ) (42 ) 2 (61 ) (72 ) 11
(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 loss of approximately $1 million for the second quarter of 2015 and a foreign exchange gain of approximately $8 million year-to-date 2015, compared to a foreign exchange loss of approximately $4 million for the second quarter of 2014 and no net foreign exchange impact year-to-date 2014, 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 $18 million ($13 million after tax) and $34 million ($24 million after tax) for the second quarter and year-to-date 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) and $4 million ($3 million after tax) for the second quarter and year-to-date 2014, respectively, related to the acquisition of UNS Energy.

Excluding the above-noted items, net Corporate and Other expenses were $39 million and $69 million for the quarter and year to date, respectively, compared to $24 million and $45 million, respectively, for the same periods 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 unfavorable foreign exchange associated with the translation of US-dollar denominated interest expense. Higher operating expenses also contributed to the increase, which was partially offset by a higher income tax recovery.

The increase in operating expenses was mainly due to a $3 million ($2 million after tax) corporate donation in the second quarter of 2015. Retirement expenses of approximately $2 million ($1 million after tax) were recognized in the second quarter of 2015, compared to approximately $4 million ($3 million after tax) for the same period last year.

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 half of 2015.

UNS Energy

In June 2015 Tucson Electric Power Company ("TEP"), UNS Energy's largest utility, announced its plan to file a general rate application ("GRA") before the end of this year requesting new retail rates to be effective January 1, 2017, using June 30, 2015 as a historical test year. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.8 billion.

Central Hudson

In June 2015 the PSC issued a Rate Order for Central Hudson covering a three-year period, with new electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson invested approximately US$250 million in energy infrastructure during the two-year delivery rate freeze period ending June 30, 2015. The approved Rate Order reflects an allowed ROE of 9.0% and a 48% common equity component of capital structure. The Rate Order includes capital investments of approximately US$490 million during the three-year period targeted at making the electric and gas systems stronger.

The approved Rate Order includes continuation of certain mechanisms currently in place, including revenue decoupling and earnings sharing mechanisms. In the approved 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. In addition, the Rate Order includes a major storm reserve for electric operations and provides for continuation of recovery of various operating expenses, including environmental site investigation and remediation costs. To the extent that Central Hudson receives gas delivery revenue associated with a new contract in late 2014, beginning July 1, 2015, associated revenue will be used to mitigate future gas customer rate increases.

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 reverted to those of FEI, which are 8.75% and 38.5%, respectively.

In May 2015 and June 2015, the BCUC issued its decisions on FEI and FortisBC Electric's 2015 rates in compliance with the PBR decisions issued in September 2014. The decisions approved 2015 midyear rate base of approximately $3,661 million and $1,249 million for FEI and FortisBC Electric, respectively, and approved customer rate increases for 2015 of 0.7% and 4.2% over 2014 rates, respectively. For FortisBC Electric, this decision results in the Company applying a 3.5% rate increase from January 1, 2015 to July 31, 2015, and a 5.1% rate increase effective August 1, 2015, both as compared to 2014 rates.

FEI is required to file an application to review the 2016 benchmark allowed ROE and common equity component of capital structure no later than November 30, 2015. As FEI is the benchmark utility, the review of the application could also 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 that the majority of the Company's applied for capital trackers 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) confirmed 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 $9 million was recognized in the first half 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 reflected in current customer rates.

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

In April 2015 the AUC initiated a GCOC Proceeding to set the allowed ROE and capital structure for 2016 and 2017. The AUC will hold a pre-hearing conference in the third quarter of 2015 to establish scope and process matters. With the current PBR term expiring in 2017, the AUC has also initiated a generic proceeding to establish parameters for the next generation of PBR plans. Further information from the AUC with respect to this proceeding is expected in the second half of 2015.

Eastern Canadian Electric Utilities

In April 2015 Newfoundland Power filed an application with the Newfoundland and Labrador Board of Commissioners of Public Utilities ("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. In July 2015 the PUB issued an order denying the Company's application. Newfoundland Power will file its GRA with the PUB on or before October 16, 2015 to establish customer rates for 2016.

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
TEP GRA Fourth quarter of 2015 To be determined
Central Hudson Reforming the Energy Vision Not applicable To be determined
FEI 2016 Cost of Capital Application Fourth quarter of 2015 To be determined
FortisAlberta Capital Tracker Compliance Filing April 2015 Second half of 2015
2016/2017 Capital Tracker Application May 2015 First quarter of 2016
Newfoundland Power GRA Fourth quarter of 2015 To be determined

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between June 30, 2015 and December 31, 2014.

Significant Changes in the Consolidated Balance Sheets (Unaudited) between
June 30, 2015 and December 31, 2014

Balance Sheet Account
Increase/
(Decrease)
($ millions)
Explanation
Cash and cash equivalents 567 The increase was driven by cash on hand at Fortis Properties due to net proceeds received from the sale of its commercial real estate assets in June 2015. Cash on hand at UNS Energy and Central Hudson also contributed to the increase.
Accounts receivable and other current assets (86) The decrease was primarily due to the impact of a seasonal decrease in sales at FortisBC Energy, FortisBC Electric and Newfoundland Power. The decrease was partially offset by the operation of equal payment plans for customers, mainly at FortisBC Energy and Newfoundland Power, and a seasonal increase in sales at UNS Energy.
Assets held for sale 398 The increase was primarily due to the pending sale of Fortis Properties' hotel assets, which were reclassified from non-utility capital assets.
Utility capital assets 970 The increase was primarily due to utility capital expenditures and the impact of foreign exchange on the translation of US dollar-denominated utility capital assets, partially offset by depreciation.
Non-utility capital assets (664) The decrease was due to the sale of Fortis Properties' commercial real estate assets in June 2015 and the pending sale of its hotel assets, which were reclassified to assets held for sale.
Goodwill 176 The increase was due to the impact of foreign exchange on the translation of US dollar-denominated goodwill.
Short-term borrowings (169) The decrease was primarily due the repayment of short-term borrowings at FortisBC Energy using proceeds from the issuance of long-term debt.
Long-term debt
(including current portion)
1,016 The increase was primarily due the issuance of long-term debt at UNS Energy, FortisBC Energy and Central Hudson, and the impact of foreign exchange on the translation of US-dollar denominated debt. Higher credit facility borrowings at the Corporation and FortisAlberta were partially offset by lower credit facility borrowings at UNS Energy. The increase was partially offset by regularly scheduled debt repayments.
Capital lease and finance obligations (including current portion) (197) The decrease was mainly due to the purchase of an additional ownership interest in the Springerville Unit 1 generating facility and the Springerville coal handling facilities at UNS Energy following the expiry of lease arrangements.
Deferred income tax liabilities - current and long-term 131 The increase was mainly due to the impact of foreign exchange on the translation of US dollar-denominated deferred income tax liabilities, an increase in the provincial statutory tax rate at FortisAlberta, and tax timing differences mainly related to capital expenditures at the regulated utilities.
Shareholders' equity (before non-controlling interests) 596 The increase primarily related to: (i) net earnings attributable to common equity shareholders for the six months ended June 30, 2015, less dividends declared on common shares; (ii) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax; and (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 and six months ended June 30, 2015, as compared to the same periods in 2014, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2015 2014 Variance 2015 2014 Variance
Cash, Beginning of Period 299 528 (229 ) 230 72 158
Cash Provided by (Used in):
Operating Activities 468 321 147 918 586 332
Investing Activities (135 ) (288 ) 153 (688 ) (398 ) (290 )
Financing Activities 166 55 111 322 356 (34 )
Effect of Exchange Rate Changes on
Cash and Cash Equivalents (2 ) (4 ) 2 17 (4 ) 21
Change in Cash Associated with Assets
Held for Sale 1 - 1 (2 ) - (2 )
Cash, End of Period 797 612 185 797 612 185

Operating Activities: Cash flow from operating activities was $147 million higher for the quarter and $332 million higher year to date compared to the same periods last year. The increase was primarily due to higher cash earnings, largely due to the acquisition of UNS Energy in August 2014. The increase for the quarter was partially offset by unfavourable changes in working capital, mainly associated with accounts receivable at FortisBC Energy, FortisBC Electric and UNS Energy, and current regulatory deferrals at FortisBC Energy and Central Hudson. Favourable changes in working capital, mainly associated with accounts receivable and current regulatory deferrals at FortisBC Energy, contributed to the year-to-date increase in cash flow from operating activities.

Investing Activities: Cash used in investing activities was $153 million lower quarter over quarter. The decrease was primarily due to the sale of Fortis Properties' commercial real estate assets and generation assets in Upstate New York in June 2015 for proceeds of approximately $430 million and $77 million (US$63 million), respectively. The decrease was partially offset by capital expenditures at UNS Energy and higher capital spending at FortisBC Energy, FortisAlberta and FortisBC Electric.

Cash used in investing activities was $290 million higher year to date compared to the same period last year. The increase was driven by capital expenditures at UNS Energy and higher capital spending at FortisBC Energy, FortisAlberta and FortisBC Electric, partially offset by lower capital spending at the non-regulated Waneta Expansion. The increase was partially offset by proceeds received on the sale of Fortis Properties' commercial real estate assets and generation assets in Upstate New York, as discussed above, compared to proceeds of approximately $105 million (US$95 million) on the sale of Griffith for the same period last year.

Financing Activities: Cash provided by financing activities was $111 million higher quarter over quarter. The increase was primarily due to higher net proceeds from committed credit facility borrowings, partially offset by higher repayments of short-term borrowings at FortisBC Energy.

Cash provided by financing activities was $34 million lower year to date compared to the same period last year. The decrease was primarily due to lower proceeds from the Corporation's convertible debentures and higher repayments of long-term debt and short-term borrowings, partially offset by higher net proceeds from committed credit facility borrowings and higher proceeds from the issuance of long-term debt.

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 and year to date compared to the same periods last year are summarized in the following tables.

Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2015 2014 Variance 2015 2014 Variance
UNS Energy (1) 61 - 61 431 - 431
Central Hudson (2) - - - 25 33 (8 )
FortisBC Energy (3) 150 - 150 150 - 150
Corporate (4) - 227 (227 ) - 227 (227 )
Other (5) - - - 12 - 12
Total 211 227 (16 ) 618 260 358
(1) In February 2015 TEP issued 10-year US$300 million 3.05% senior unsecured notes. Net proceeds were used to repay long-term debt and credit facility borrowings and to finance capital expenditures. In April 2015 UNS Electric issued 30-year US$50 million 3.95% unsecured notes. The net proceeds were primarily used to repay short-term borrowings. In April 2015 UNS Electric and UNS Gas entered into private placement financing agreements. In August 2015 UNS Electric will issue 12-year US$80 million 3.22% unsecured debentures and UNS Gas will issue 30-year US$45 million 4.00% unsecured notes. The net proceeds will be used to repay maturing long-term debt and for general corporate purposes.
(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 April 2015 FortisBC Energy issued 30-year $150 million 3.38% unsecured debentures. The net proceeds were used to repay short-term borrowings and for general corporate purposes.
(4) In June 2014 the Corporation issued US$213 million unsecured notes with terms to maturity ranging from 5 to 30 years and coupon rates ranging from 2.92% to 4.80%. The notes have a weighted average term to maturity of approximately 9 years and a weighted average coupon rate of 3.51%. Net proceeds were used to repay US dollar-denominated borrowings on the Corporation's committed credit facility and for general corporate purposes.
(5) In January 2015 Fortis Turks and Caicos issued 15-year US$10 million 4.75% unsecured notes. The net proceeds were used to finance capital expenditures and for general corporate purposes.
Repayments of Long-Term Debt and Capital Lease and Finance Obligations (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2015 2014 Variance 2015 2014 Variance
UNS Energy (5 ) - (5 ) (173 ) - (173 )
Central Hudson - (8 ) 8 - (16 ) 16
FortisBC Energy (12 ) (2 ) (10 ) (14 ) (3 ) (11 )
Caribbean Utilities (13 ) (15 ) 2 (13 ) (15 ) 2
Other (36 ) (8 ) (28 ) (36 ) (10 ) (26 )
Total (66 ) (33 ) (33 ) (236 ) (44 ) (192 )
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2015 2014 Variance 2015 2014 Variance
UNS Energy (35 ) - (35 ) (122 ) - (122 )
FortisAlberta 36 - 36 82 (20 ) 102
FortisBC Electric - - - - (79 ) 79
Newfoundland Power 8 - 8 27 - 27
Corporate (1) 272 (128 ) 400 275 (174 ) 449
Total 281 (128 ) 409 262 (273 ) 535
(1) Borrowings under the Corporation's credit facility were primarily used for equity injections into UNS Energy and FEI and for other general corporate purposes.

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 second quarter of 2015 were $55 million, net of $40 million of dividends reinvested, compared to $48 million, net of $20 million of dividends reinvested, paid in the same quarter of 2014. Common share dividends paid year-to-date 2015 were $115 million, net of $74 million in dividends reinvested, compared to $95 million, net of $42 million in dividends reinvested, paid year-to-date 2014. The dividend paid per common share for the first and second quarters of 2015 was $0.34 compared to $0.32 for the first and second quarters of 2014. The weighted average number of common shares outstanding for the second quarter and year-to-date 2015 was 277.9 million and 277.3 million, respectively, compared to 214.8 million and 214.2 million for the same periods in 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 June 30, 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 June 30, 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 11,517 869 351 71 416 60 9,750
Interest obligations on long-term debt 9,013 512 488 473 466 454 6,620
Capital lease and finance obligations 2,450 68 70 63 91 76 2,082
Power purchase obligations (1) (2) 1,583 283 239 195 135 62 669
Renewable power purchase obligations 1,074 63 63 63 63 63 759
Long-term contracts - UNS Energy 1,004 136 132 111 93 83 449
Gas purchase contract obligations 672 210 82 62 59 53 206
Capital cost 522 22 19 21 19 22 419
Operating lease obligations 172 13 11 11 11 10 116
Defined benefit pension funding contributions 162 63 22 10 9 9 49
Renewable energy credit purchase agreements 150 11 11 11 11 11 95
Purchase of Springerville common facilities 133 - - 48 - - 85
Waneta Partnership promissory note 72 - - - - - 72
Joint-use asset and shared service agreements 54 3 3 3 3 3 39
Other 71 6 10 13 3 - 39
Total 28,649 2,259 1,501 1,155 1,379 906 21,449
(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 $162 million as at June 30, 2015.
(2) FortisBC Energy has entered into an Electricity Supply Agreement with BC Hydro for the purchase of electrical service to the Tilbury Expansion Project, with obligations totalling approximately $548 million as at June 30, 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
June 30, 2015 December 31, 2014
($ millions) (%) ($ millions) (%)
Total debt and capital lease and finance obligations (net of cash) (1) 11,387 55.1 11,304 56.5
Preference shares 1,820 8.8 1,820 9.1
Common shareholders' equity 7,467 36.1 6,871 34.4
Total (2) 20,674 100.0 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 June 30, 2015 was 54.0% debt, 9.0% preference shares and 37.0% common shareholders' equity (December 31, 2014 - 55.0% debt, 9.4% preference shares and 35.6% common shareholders' equity).

The improvement in the capital structure was due to an increase in common shareholder's equity as a result of: (i) net earnings attributable to common equity shareholders for the six months ended June 30, 2015, less dividends declared on common shares; (ii) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans. The capital structure was also impacted by an increase in total debt, mainly due to the issuance of long-term debt, largely in support of energy infrastructure investment, and the impact of foreign exchange on the translation of US-dollar denominated debt, partially offset by regularly scheduled debt repayments and increase in cash on hand, driven by Fortis Properties.

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 $1,171 million in gross consolidated capital expenditures by segment for the first half of 2015 is provided in the following table.

Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date June 30, 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
449 67 239 207 60 73 44 1,139 19 13 1,171
(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 AFUDC.

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. 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. The expansion added 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. On April 2, 2015, the Waneta Expansion began generating power, all of which is being sold to BC Hydro and FortisBC Electric under 40-year contracts.

Construction of FEI's Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury 1A") in Delta, British Columbia is ongoing. Key construction activities during the second quarter were completion of geotechnical work and continued construction of the LNG tank and civil work in the process and substation areas. Tilbury 1A will be included in regulated rate base and is estimated to cost approximately $440 million, including an equity component of AFUDC. It will include a second LNG tank and a new liquefier, both expected to be in service by the end of 2016. Approximately $223 million has been invested in Tilbury 1A to date.

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 an additional ownership interest in the previously leased coal-handling assets for US$72 million.

The Pinal Transmission Project at UNS Energy is the construction of a 500-kilovolt transmission line in Pinal County that will increase the Company's import capacity from the Palo Verde trading hub. During the second quarter, all structures were framed, set and anchor bolts installed. The conductor wires, optical ground wires and static wires were installed from the substation to a portion of the structures. Construction is expected to be completed by the end of 2015 at a total project cost of US$78 million, of which approximately US$60 million has been invested to date.

Caribbean Utilities was the successful bidder for new generation capacity and entered into a design-build contract agreement to cover the purchase and turnkey installation of two 18.5 MW diesel-generating units, one 2.7 MW waste heat recovery steam turbine and associated auxiliary equipment. Key construction activities during the second quarter included completion of piling, foundation work for the first engine and three boreholes. The project cost is estimated at US$85 million and the plant is expected to be commissioned by June 2016. Approximately US$18 million has been invested to date.

FortisBC is pursuing additional LNG infrastructure investment opportunities, including a further expansion of Tilbury ("Tilbury 1B") and a pipeline expansion to the proposed Woodfibre LNG site 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 BCUC; 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 Corporation continues to have discussions with Hawaiian Electric Company, which is expected to be the primary offtaker, regarding the viability and scope of the project. Any resulting agreement would be subject to the approval of the Hawaii Public Utilities Commission. The pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. These additional investment opportunities, at an estimate of more than $1 billion, are not included in the Corporation's capital expenditure forecast.

Over the five-year period through 2019, gross consolidated capital expenditures are expected to exceed $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 38% at U.S. Regulated Electric & Gas Utilities; 36% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 19% 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 the Company 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 3.38% unsecured debentures under the base shelf prospectus. The net proceeds were used to repay short-term borrowings.

In June 2015 Fortis injected US$180 million of equity into TEP. Proceeds were used to repay credit facility borrowings and the balance will be used to repay upcoming debt maturities. This equity injection fulfilled one of the commitments made by Fortis in order to receive regulatory approval for the acquisition of UNS Energy, and increased TEP's equity thickness to almost 50%, which is comparable with other regulated utilities in Arizona.

In May 2015 Caribbean Utilities completed a rights offering in which it raised gross proceeds of US$32 million through the issue of 2.9 million common shares. Fortis invested US$23 million in approximately 2.2 million common shares of Caribbean Utilities. The net proceeds from the rights offering will be used by Caribbean Utilities to finance capital expenditures.

As at June 30, 2015, management expects consolidated fixed-term debt maturities and repayments to average approximately $200 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 June 30, 2015 and are expected to remain compliant throughout 2015.

CREDIT FACILITIES

As at June 30, 2015, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.7 billion, of which approximately $2.0 billion was unused, including $209 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 $3.5 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 June 30, December 31,
($ millions) Utilities Regulated and Other 2015 2014
Total credit facilities (1) 2,070 13 1,617 3,700 3,854
Credit facilities utilized:
Short-term borrowings (161 ) - - (161 ) (330 )
Long-term debt (2) (197 ) - (1,182 ) (1,379 ) (1,096 )
Letters of credit outstanding (172 ) - (34 ) (206 ) (192 )
Credit facilities unused 1,540 13 401 1,954 2,236
(1) Total credit facilities exclude a $300 million increase to the Corporation's committed corporate credit facility in March 2015, as discussed below.
(2) As at June 30, 2015, credit facility borrowings classified as long-term debt included $591 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2014 - $257 million).

As at June 30, 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 the ability to increase the facility to $1.3 billion and an extension of the maturity date to July 2020 from July 2018. As at June 30, 2015, the Corporation has not yet exercised its option for the additional $300 million.

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 June 2015 UNS Energy terminated the associated credit agreement, which also included US$70 million in unsecured committed revolving credit facilities.

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

In June 2015 FortisOntario amended its $30 million unsecured committed revolving credit facility to now mature in June 2016.

In July 2015 FortisAlberta renegotiated and amended its $250 million unsecured committed revolving credit facility, extending the maturity date to August 2020 from August 2019.

In July 2015 CH Energy Group amended its US$100 million committed credit facility, resulting in a decrease in the facility to US$50 million and an extension of the maturity date to July 2020 from October 2015.

In July 2015 the Corporation repaid its $273 million medium-term bridge facility using net proceeds from the sale of commercial real estate assets.

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
June 30, 2015 December 31, 2014
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
Waneta Partnership promissory note 54 57 53 56
Long-term debt, including current portion 11,517 13,027 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 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 $124 million as at June 30, 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 June 30, December 31,
($ millions) hierarchy 2015 2014
Assets
Energy contracts subject to regulatory deferral (1) (2) (3) Levels 2/3 3 3
Energy contracts not subject to regulatory deferral (1) (2) Level 3 4 1
Available-for-sale investment (4) (5) Level 1 33 -
Other investments (4) Level 1 13 5
Total gross assets 53 9
Less: Counterparty netting not offset on the balance sheet (6) (3) (3)
Total net assets 50 6
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (7) Levels 1/2/3 79 72
Energy contracts not subject to regulatory deferral (1) (2) Level 3 - 1
Energy contracts - cash flow hedges (2) (8) Level 3 1 1
Interest rate swaps - cash flow hedges (8) Level 2 5 5
Total gross liabilities 85 79
Less: Counterparty netting not offset on the balance sheet (6) (3) (3)
Total net liabilities 82 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 wholesale trading 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 wholesale trading contracts.
(3) Includes $1 million - level 2 and $2 million - level 3 (2014 - $3 million - level 3)
(4) Included in long-term other assets on the consolidated balance sheet.
(5) The cost of the available-for-sale investment was $35 million and 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.
(6) 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.
(7) Includes $49 million - level 2 and $30 million - level 3 (2014 - $2 million - level 1, $35 million - level 2 and $35 million - level 3)
(8) 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, or those that are approved for regulatory recovery. 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 June 30, 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 June 30, 2015, unrealized losses of $76 million (December 31, 2014 - $69 million) were recognized in current regulatory assets and no unrealized gains were recognized in regulatory liabilities.

Energy Contracts Not Subject to Regulatory Deferral

In June 2015 UNS Energy entered into long-term wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recorded in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with the ratepayer through UNS Energy's rate stabilization accounts.

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 $2 million.

Central Hudson holds interest rate cap contracts expiring in 2016 and 2017 on bonds with a total principal amount of US$64 million. Variations in the interest costs of the bonds, including any gains or losses associated with the interest rate cap contracts, are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulator and do not impact earnings.

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 June 30, 2015, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

Maturity Contracts There-
Volume (year) (#) 2015 2016 2017 2018 2019 after
Energy contracts subject to regulatory deferral:
Electricity swap contracts (GWh) 2017 9 686 659 219 - - -
Electricity power purchase contracts (GWh) 2017 35 880 780 145 - - -
Gas swap and option contracts (PJ) 2017 194 26 28 7 - - -
Gas purchase contract premiums (PJ) 2024 51 51 34 18 18 18 80
Energy contracts not subject to regulatory deferral:
Long-term wholesale trading contracts (GWh) 2016 6 1,325 1,310 - - - -
Energy contracts - cash flow hedges (GWh) 2015 1 44 - - - - -

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $206 million as at June 30, 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 has resulted in the refusal of third-party owners to pay 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, 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 ("Moody's") upgraded the debt credit ratings of UNS Energy to 'Baa1' from 'Baa2' and TEP, UNS Electric and UNS Gas to 'A3' from 'Baa1'. In July 2015 Fitch Ratings downgraded Central Hudson's debt credit rating to 'A-' from 'A' and changed the rating outlook to Stable from Negative. Central Hudson's debt continues to be rated 'A' by S&P and 'A2' by Moody's, both with Stable outlooks.

Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at June 30, 2015, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $2,495 million, up $125 million or 5% from $2,370 million as at December 31, 2014.

Labour Relations: The collective agreement between FortisBC Energy and Canadian Office and Professional Employees Union, representing employees in specified occupations in the areas of administration and operations support expired on March 31, 2015 and was renewed in the second quarter for a three-year term which expires on March 31, 2018.

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 ratified in June 2015. The contracts expire in September 2017.

CHANGES IN ACCOUNTING POLICIES

The 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.

Available-for-Sale Assets

The Corporation's assets designated as available-for-sale are measured at fair value based on quoted market prices. Unrealized gains or losses resulting from changes in fair value are recognized in accumulated other comprehensive income and are reclassified to earnings when the asset is sold.

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

Effective January 1, 2015, the Corporation adopted amendments to Accounting Standards Codification ("ASC"), Topics 205 and 360, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, as outlined in Accounting Standards Update ("ASU") No. 2014-08. The amendments were applied prospectively and, as a result, the sale of commercial real estate assets and non-regulated generation assets in June 2015 did not meet the new criteria for discontinued operations. The sales are consistent with the Corporation's focus on its core utility business and, therefore, do not represent a strategic shift in operations.

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

Effective January 1, 2015, the Corporation early adopted amendments to ASC 718, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period as outlined in ASU No. 2014-12. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and six months ended June 30, 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 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 July 2015 FASB decided to defer 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.

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 change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. 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 June 30, 2015, debt issuance costs included in long-term other assets were approximately $69 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 six months ended June 30, 2015 from those disclosed in the 2014 Annual MD&A, with the 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 and $3 million for the three and six months ended June 30, 2015, respectively.

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. In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged, the third-party owners have twice amended the complaint, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases; that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action; that TEP breached the lease transaction documents by refusing to pay certain of the third-party owners' claimed expenses; and that TEP has breached an implied covenant of good faith and fair dealing. The amended complaint seeks US$71 million in liquidated damages, direct and consequential damages in an amount to be determined at trial, and punitive damages. In the amended complaint, the third-party owners agree to stay the claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. A motion filed by TEP to dismiss the cause of action for breach of the implied covenant of good faith and fair dealing and to dismiss the punitive damages claims in the amended complaint is pending.

In December 2014 and January 2015, Wilmington Trust Company, as owner trustees and lessors under the leases of the third-party owners, sent notices to TEP that alleged that TEP had defaulted under the third-party owners' leases. The notices demanded that TEP pay liquidated damages totalling approximately US$71 million. In letters to Wilmington Trust Company, TEP denied the allegations in the notices.

In April 2015 TEP filed a demand for arbitration with the American Arbitration Association ("AAA") seeking an award of the third-party owners' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015 the third-party owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The third-party owners' arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the third-party owners' fees and expenses. TEP and the third-party owners have since agreed to consolidate their arbitration demands into one proceeding. The third-party owners have moved to dismiss TEP's arbitration demand. As at June 30, 2015, TEP billed the third-party owners approximately US$11 million for their pro-rata share of Springerville Unit 1 operating expenses and US$1 million for their pro-rata share of capital expenditures, none of which had been paid as of July 30, 2015.

Under the Springerville Unit 1 facility support agreement, TEP is permitted to dispatch and use any of the third-party owners' unscheduled entitlement share of power from Springerville Unit 1. TEP commenced such dispatch and use for TEP's benefit in June 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 claims, the Company cannot determine estimates of the range of loss, if any, 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, 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. Upon expiration of the coal supply agreements, which expire between 2017 and 2031, TEP's share of reclamation costs at all three mines is expected to be US$52 million. The mine reclamation liability recorded as at June 30, 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

Site Investigation and Remediation Program

Central Hudson and its predecessors owned and operated manufactured gas plants ("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 June 30, 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 PSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for MGP site investigation and remediation and the associated rate allowances, with carrying charges to be accrued on the deferred balances at the authorized pre-tax rate of return. As authorized by the PSC in the three-year Rate Order issued in June 2015, Central Hudson is permitted to defer all MGP site investigation and remediation costs incurred during the period of July 1, 2015 to June 30, 2018.

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 3,349 asbestos cases have been raised, 1,171 remained pending as at June 30, 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 notified its insurers, it has been advised by the Government of British Columbia that a response to the claim is not required at this time. 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 September 30, 2013 through June 30, 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 ($) Diluted ($)
June 30, 2015 1,538 244 0.88 0.87
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

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 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.

June 2015/June 2014: Net earnings attributable to common equity shareholders were $244 million, or $0.88 per common share, for the second quarter of 2015 compared to earnings of $47 million, or $0.22 per common share, for the second 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.

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. The increase in earnings was driven by the Corporation's regulated utilities. UNS Energy contributed earnings of $20 million in the first quarter of 2015. FortisAlberta's earnings were favourably impacted by higher capital tracker revenue, including approximately $10 million associated with 2013 and 2014, and customer growth. 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. 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, costs at Fortis Properties associated with the strategic review, and approximately $5 million earnings contribution in the first quarter of 2014 from Griffith to the date of sale. Corporate and Other expenses were lower quarter over quarter, due to approximately $11 million in after-tax interest expense associated with the convertible debentures in the first quarter of 2014 and a higher foreign exchange gain, partially offset by higher preference share dividends and finance charges associated with the acquisition of UNS Energy.

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 Corporate and Other expenses and lower earnings at Central Hudson. The increase in 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.

OUTLOOK

Fortis is a leader in the North American electric and gas utility business, 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.

The pending sale of Fortis Properties' hotel assets is expected to be completed in the fall of 2015. The sale of the commercial real estate and hotel assets is consistent with the Corporation's focus on its core utility business. Post closing of the hotel transaction, virtually all of the Corporation's assets will be comprised of regulated utilities and long-term contracted energy infrastructure.

Over the five-year period through 2019, the Corporation's capital program is expected to exceed $9 billion. This investment in energy infrastructure is expected to increase midyear rate base by approximately 40% from $14 billion in 2014 to approximately $19.5 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 the Woodfibre LNG site - 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 July 30, 2015, the Corporation had issued and outstanding approximately 278.7 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; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 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 July 30, 2015 is as follows.

Conversion of Securities into Common Shares(Unaudited)
As at July 30, 2015 Number of
Common Shares
Security (millions)
Stock Options 4.8
First Preference Shares, Series E 5.8
Total 10.6

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 and six months ended June 30, 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)
June 30,December 31,
20152014
ASSETS
Current assets
Cash and cash equivalents$797$230
Accounts receivable and other current assets 814 900
Prepaid expenses 52 59
Inventories 287 321
Regulatory assets (Note 5) 253 295
Assets held for sale (Note 6) 398 -
Deferred income taxes 159 158
2,760 1,963
Other assets 391 337
Regulatory assets (Note 5) 2,319 2,230
Deferred income taxes 46 62
Utility capital assets 18,122 17,152
Non-utility capital assets - 664
Intangible assets 523 488
Goodwill 3,908 3,732
$28,069$26,628
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 18)$161$330
Accounts payable and other current liabilities 1,401 1,440
Regulatory liabilities (Note 5) 223 192
Current installments of long-term debt 869 525
Current installments of capital lease and finance obligations 25 208
Deferred income taxes 31 9
2,710 2,704
Other liabilities 1,180 1,141
Regulatory liabilities (Note 5) 1,357 1,363
Deferred income taxes 1,946 1,837
Long-term debt 10,648 9,976
Capital lease and finance obligations 481 495
18,322 17,516
Shareholders' equity
Common shares (1)(Note 8) 5,762 5,667
Preference shares (Note 9) 1,820 1,820
Additional paid-in capital 14 15
Accumulated other comprehensive income 378 129
Retained earnings 1,313 1,060
9,287 8,691
Non-controlling interests 460 421
9,747 9,112
$28,069$26,628
(1) No par value. Unlimited authorized shares; 278.6 million and 276.0 million issued and outstanding as at June 30, 2015 and December 31, 2014, respectively
Commitments and Contingencies (Notes 19 and 21, respectively)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Six Months Ended
20152014 20152014
Revenue$1,538$1,056 $3,453$2,511
Expenses
Energy supply costs 531 403 1,364 1,082
Operating 458 307 931 626
Depreciation and amortization 220 149 435 297
1,209 859 2,730 2,005
Operating income 329 197 723 506
Other income (expenses), net (Note 12) 166 (1) 183 6
Finance charges (Note 13) 141 124 275 247
Earnings before income taxes and discontinued operations 354 72 631 265
Income tax expense (Note 14) 76 9 133 48
Earnings from continuing operations 278 63 498 217
Earnings from discontinued operations, net of tax (Note 7) - - - 5
Net earnings$278$63 $498$222
Net earnings attributable to:
Non-controlling interests$15$3 $17$5
Preference equity shareholders 19 13 39 27
Common equity shareholders 244 47 442 190
$278$63 $498$222
Earnings per common share from continuing operations(Note 15)
Basic$0.88$0.22 $1.59$0.87
Diluted$0.87$0.22 $1.58$0.86
Earnings per common share (Note 15)
Basic$0.88$0.22 $1.59$0.89
Diluted$0.87$0.22 $1.58$0.88
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2015 2014 2015 2014
Net earnings$278 $63 $498 $222
Other comprehensive (loss) income
Unrealized foreign currency translation (losses) gains, net of hedging activities and tax (49) (28) 249 2
Reclassification to earnings of foreign currency translation loss on disposal of investment in foreign operations, net of tax 2 - 2 -
Unrealized losses on available-for-sale investment (2) - (2) -
Unrealized employee future benefits gains, net of tax 1 - - 1
(48) (28) 249 3
Comprehensive income$230 $35 $747 $225
Comprehensive income attributable to:
Non-controlling interests$15 $3 $17 $5
Preference equity shareholders 19 13 39 27
Common equity shareholders 196 19 691 193
$230 $35 $747 $225
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2015 2014 2015 2014
Operating activities
Net earnings$278 $63 $498 $222
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation - capital assets 198 130 391 260
Amortization - intangible assets 16 13 32 26
Amortization - other 6 6 12 11
Deferred income tax expense (recovery) 48 (9) 39 (16)
Accrued employee future benefits 11 8 14 (1)
Equity component of allowance for funds used during construction (Note 12) (5) (1) (9) (3)
Gain on sale of non-utility capital assets (Note 12) (133) - (133) -
Gain on sale of non-regulated generation assets (Note 12) (57) - (57) -
Other 32 6 28 7
Change in long-term regulatory assets and liabilities (28) (37) (76) (7)
Change in non-cash operating working capital (Note 16) 102 142 179 87
468 321 918 586
Investing activities
Change in other assets and other liabilities (41) 1 (56) 4
Capital expenditures - utility capital assets (578) (278) (1,108) (499)
Capital expenditures - non-utility capital assets (5) (7) (9) (16)
Capital expenditures - intangible assets (34) (13) (54) (20)
Purchase of assets held for sale (Note 6) (27) - (27) -
Contributions in aid of construction 13 8 28 26
Proceeds on sale of assets (Notes 6 and 7) 537 1 538 107
(135) (288) (688) (398)
Financing activities
Change in short-term borrowings (201) 37 (201) (61)
Proceeds from convertible debentures, net of issue costs - - - 561
Proceeds from long-term debt, net of issue costs 211 227 618 260
Repayments of long-term debt and capital lease and finance obligations (66) (33) (236) (44)
Net borrowings (repayments) under committed credit facilities 281 (128) 262 (273)
Advances from non-controlling interests 14 4 19 17
Issue of common shares, net of costs and dividends reinvested (Note 8) 3 12 20 23
Dividends
Common shares, net of dividends reinvested (55) (48) (115) (95)
Preference shares (19) (13) (39) (27)
Subsidiary dividends paid to non-controlling interests (2) (3) (6) (5)
166 55 322 356
Effect of exchange rate changes on cash and cash equivalents (2) (4) 17 (4)
Change in cash and cash equivalents 497 84 569 540
Change in cash associated with assets held for sale (Note 6) 1 - (2) -
Cash and cash equivalents, beginning of period 299 528 230 72
Cash and cash equivalents, end of period$797 $612 $797 $612
Supplementary Information to Consolidated Statements of Cash Flows (Note 16)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Accumulated
Additional Other Non-
CommonPreferencePaid-in Comprehensive Retained Controlling Total
SharesSharesCapital Income (Loss) Earnings Interests Equity
(Note 8)(Note 9)
As at January 1, 2015$5,667$1,820$15 $129 $1,060 $421 $9,112
Net earnings - - - - 481 17 498
Other comprehensive income - - - 249 - - 249
Common share issues 95 - (2) - - - 93
Stock-based compensation - - 1 - - - 1
Advances from non-controlling interests - - - - - 19 19
Foreign currency translation impacts - - - - - 9 9
Subsidiary dividends paid to non-controlling interests - - - - - (6) (6)
Dividends declared on common shares ($0.68 per share) - - - - (189) - (189)
Dividends declared on preference shares - - - - (39) - (39)
As at June 30, 2015$5,762$1,820$14 $378 $1,313 $460 $9,747
As at January 1, 2014$3,783$1,229$17 $(72)$1,044 $375 $6,376
Net earnings - - - - 217 5 222
Other comprehensive income - - - 3 - - 3
Common share issues 66 - (2) - - - 64
Stock-based compensation - - 2 - - - 2
Advances from non-controlling interests - - - - - 17 17
Foreign currency translation impacts - - - - - 3 3
Subsidiary dividends paid to non-controlling interests - - - - - (5) (5)
Dividends declared on common shares ($0.64 per share) - - - - (137) - (137)
Dividends declared on preference shares - - - - (27) - (27)
As at June 30, 2014$3,849$1,229$17 $(69)$1,097 $395 $6,518
See accompanying Notes to Interim Consolidated Financial Statements

FORTIS INC.

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

For the three and six months ended June 30, 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. ("FortisBC Energy" or "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 is primarily comprised of non-regulated generation assets in British Columbia and Belize. On April 1, 2015, the Corporation completed construction of the $900 million Waneta Expansion hydroelectric generating facility. In June 2015 the Corporation sold its non-regulated generation assets in Upstate New York (Note 7). In July 2015 the Corporation closed the sale of its non-regulated generation assets in Ontario. As at June 30, 2015, the associated assets have been classified as held for sale on the consolidated balance sheet (Note 6).

NON-REGULATED - NON-UTILITY

Fortis Properties Corporation ("Fortis Properties") completed the sale of its commercial real estate assets in June 2015 (Note 7) and signed an agreement for the sale of its hotel assets in July 2015. As at June 30, 2015, the associated assets have been classified as held for sale (Note 6).

Griffith Energy Services, Inc. ("Griffith") was sold in March 2014 (Note 7).

CORPORATE AND OTHER

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

The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group, Inc. ("CH Energy Group") and UNS Energy Corporation. 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 use of air conditioning and other cooling equipment. 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 and six months ended June 30, 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 and $3 million for the three and six months ended June 30, 2015, respectively.

An evaluation of subsequent events through July 30, 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 June 30, 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.

Available-for-Sale Assets

The Corporation's assets designated as available-for-sale are measured at fair value based on quoted market prices. Unrealized gains or losses resulting from changes in fair value are recognized in accumulated other comprehensive income and are reclassified to earnings when the asset is sold.

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

Effective January 1, 2015, the Corporation adopted amendments to Accounting Standards Codification ("ASC"), Topics 205 and 360, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, as outlined in Accounting Standards Update ("ASU") No. 2014-08. The amendments were applied prospectively and, as a result, the sale of commercial real estate assets and non-regulated generation assets in June 2015 did not meet the new criteria for discontinued operations (Note 7). The sales are consistent with the Corporation's focus on its core utility business and, therefore, do not represent a strategic shift in operations.

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

Effective January 1, 2015, the Corporation early adopted amendments to ASC 718, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period as outlined in ASU No. 2014-12. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and six months ended June 30, 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 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 July 2015 FASB decided to defer 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.

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 change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. 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 June 30, 2015, debt issuance costs included in long-term other assets were approximately $69 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-
June 30, 2015UNSCentral FortisBCFortisFortisBCEastern CaribbeanFortis Non-Corporate segment
($ millions)EnergyHudsonTotalEnergyAlbertaElectricCanadianTotalElectricGeneration Utilityand Other eliminations Total
Revenue494193687228136802326767441 657 (12)1,538
Energy supply costs1966426073-21143237361 -- (3)531
Operating expenses1379022766432234165115 4112 (3)458
Depreciation and amortization57147148421521126116 51 - 220
Operating income10425129415122341481629 19(6)(6)329
Other income (expenses), net1232---2-52 111(1)(1)166
Finance charges25103534209147741 724 (7)141
Income tax expense (recovery)287351-258-24 19(10)- 76
Net earnings (loss)5210628311115651256 104(21)- 278
Non-controlling interests---1---1311 -- - 15
Preference share dividends---------- -19 - 19
Net earnings (loss) attributable to common equity shareholders521062731111564945 104(40)- 244
Goodwill1,7255642,289913227235671,442177- -- - 3,908
Identifiable assets6,4612,3448,8054,9023,4261,8352,18012,3439021,030 781778 (478)24,161
Total assets8,1862,90811,0945,8153,6532,0702,24713,7851,0791,030 781778 (478)28,069
Gross capital expenditures256342901211012838288238 53 - 617
Quarter Ended
June 30, 2014
($ millions)
Revenue-190190282129712327147811 658 (10)1,056
Energy supply costs-7979119-1714327946- -- (1)403
Operating expenses-808067422135165102 439 (2)307
Depreciation and amortization-12124641141912092 51 - 149
Operating income-191950461935150137 17(2)(7)197
Other income (expenses), net-111--121(1)-(3)(1)(1)
Finance charges-883520915794- 635 (8)124
Income tax expense (recovery)-553-3511-- 4(11)- 9
Net earnings (loss)-77132671662106 7(29)- 63
Non-controlling interests---1---12- -- - 3
Preference share dividends---------- -13 - 13
Net earnings (loss) attributable tocommon equity shareholders-7712267166186 7(42)- 47
Goodwill-481481913227235671,442151- -- - 2,074
Identifiable assets-1,9101,9104,6003,1351,7612,09211,588707903 6841,356 (636)16,512
Total assets-2,3912,3915,5133,3621,9962,15913,030858903 6841,356 (636)18,586
Gross capital expenditures-2828768320382171531 7- - 298
REGULATEDNON-REGULATED
United StatesCanada
Year-to-DateElectric & Gas GasElectric Inter-
June 30, 2015UNSCentral FortisBCFortisFortisBCEastern CaribbeanFortis Non-Corporate segment
($ millions)EnergyHudsonTotalEnergyAlbertaElectricCanadianTotalElectricGeneration Utilityand Other eliminations Total
Revenue9294851,4147162821765541,72815248 11814 (21)3,453
Energy supply costs384198582290-46367703811 -- (3)1,364
Operating expenses272190462136894473342238 8517 (6)931
Depreciation and amortization1172814596832941249227 111 - 435
Operating income1566922519411057734342632 22(4)(12)723
Other income (expenses), net24651--6152 1118 (1)183
Finance charges4819676839192815481 1345 (13)275
Income tax expense (recovery)38226035-41150-24 18(19)- 133
Net earnings (loss)7232104967234342361959 102(22)- 498
Non-controlling interests---1---1511 -- - 17
Preference share dividends---------- -39 - 39
Net earnings (loss) attributable to common equity shareholders7232104957234342351448 102(61)- 442
Goodwill1,7255642,289913227235671,442177- -- - 3,908
Identifiable assets6,4612,3448,8054,9023,4261,8352,18012,3439021,030 781778 (478)24,161
Total assets8,1862,90811,0945,8153,6532,0702,24713,7851,0791,030 781778 (478)28,069
Gross capital expenditures4496751623920760735794419 94 - 1,171
Year-to-Date
June 30, 2014
($ millions)
Revenue-4624627952551665441,76015222 11915 (19)2,511
Energy supply costs-216216370-44361775911 -- (1)1,082
Operating expenses-169169138854373339194 8514 (4)626
Depreciation and amortization-232392822839241183 111 - 297
Operating income-54541958851714052414 23- (14)506
Other income (expenses), net-3322-151(1)-(1)(1)6
Finance charges-1717703919291578- 1268 (15)247
Income tax expense (recovery)-151535-71052-1 4(24)- 48
Net earnings (loss) from continuing operations-2525925125332011712 7(45)- 217
Earnings from discontinued operations, net of tax---------- 5- - 5
Net earnings (loss)-2525925125332011712 12(45)- 222
Non-controlling interests---1---14- -- - 5
Preference share dividends---------- -27 - 27
Net earnings (loss) attributable to common equity shareholders-2525915125332001312 12(72)- 190
Goodwill-481481913227235671,442151- -- - 2,074
Identifiable assets-1,9101,9104,6003,1351,7612,09211,588707903 6841,356 (636)16,512
Total assets-2,3912,3915,5133,3621,9962,15913,030858903 6841,356 (636)18,586
Gross capital expenditures-494912716235633872855 16- - 535

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 and six months ended June 30, 2015 and 2014 were as follows:

Significant Related Party Inter-Segment TransactionsQuarter EndedYear-to-Date
June 30June 30
($ millions)2015201420152014
Sales from Fortis Generation to
Regulated Electric Utilities - Canadian3131
Sales from Regulated Electric Utilities - Canadian to Non-Utility1133
Inter-segment finance charges on lending from:
Corporate to Regulated Electric Utilities - Canadian-1-1
Corporate to Regulated Electric Utilities - Caribbean-2-3
Corporate to Non-Utility651210
The significant related party inter-segment asset balances were as follows:
As at
June 30
($ millions) 20152014
Inter-segment lending from:
Fortis Generation to Eastern Canadian Electric Utilities 2020
Corporate to Regulated Gas Utility - Canadian -37
Corporate to Regulated Electric Utilities - Canadian -85
Corporate to Regulated Electric Utilities - Caribbean -96
Corporate to Non-Utility 449387
Other inter-segment assets 911
Total inter-segment eliminations 478636

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
June 30, December 31,
($ millions)2015 2014
Regulatory assets
Deferred income taxes995 942
Employee future benefits (i)657 680
Manufactured gas plant ("MGP") site remediation deferral (Note 21)130 123
Deferred energy management costs124 111
Rate stabilization accounts103 119
Deferred lease costs87 101
Derivative instruments (Note 17)76 69
Deferred operating overhead costs60 54
Deferred net losses on disposal of utility capital assets and intangible assets35 37
Final mine reclamation and retiree health care costs34 34
Springerville Unit 1 unamortized leasehold improvements (ii)30 -
Property tax deferrals28 29
Natural gas for transportation incentives25 24
Income taxes recoverable on other post-employment benefit ("OPEB") plans24 24
Carrying charges - employee future benefits (i)- 20
Other regulatory assets (i)164 158
Total regulatory assets2,572 2,525
Less: current portion(253)(295)
Long-term regulatory assets2,319 2,230
As at
June 30, December 31,
($ millions)2015 2014
Regulatory liabilities
Non-asset retirement obligation removal cost provision995 951
Rate stabilization accounts148 142
Deferred income taxes106 110
Electric and gas moderator account (i)82 -
Renewable energy surcharge41 44
Alberta Electric System Operator charges deferral40 49
Employee future benefits (i)32 58
Customer and community benefits obligation (i)32 55
Carrying charges - employee future benefits (i)- 24
Deferred energy management costs23 22
Other regulatory liabilities (i)81 100
Total regulatory liabilities1,580 1,555
Less: current portion(223)(192)
Long-term regulatory liabilities1,357 1,363

Description of the Nature of Regulatory Assets and Liabilities

  1. In June 2015 the New York State Public Service Commission ("PSC") issued a Rate Order for Central Hudson covering a three-year period, with new electricity and natural gas delivery rates effective July 1, 2015. Under the terms of the Rate Order, certain regulatory assets and liabilities were identified and approved by the PSC for offset and a net regulatory liability electric and gas moderator account was established which will be used for future customer rate moderation.
  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.

6. ASSETS HELD FOR SALE

Assets held for sale as at June 30, 2015 were as follows:

RegulatedNon-Regulated
Fortis
($ millions)UNS EnergyGenerationNon-Utility Total
ASSETS
Cash and cash equivalents-2- 2
Utility capital assets278- 35
Non-utility capital assets--374 374
Total assets held for sale2710374 411
Impairment (Note 12)--(13)(13)
Net assets held for sale2710361 398

REGULATED

UNS Energy

In April 2015, upon expiration of the Springerville Coal Handling Facilities lease, UNS Energy purchased an additional ownership interest in the previously leased coal handling assets for a total of US$120 million. In May 2015 UNS Energy sold a 17.05% interest in the facilities to a third party for US$24 million and has an agreement with another third party to either purchase a 17.05% interest for US$24 million or to continue to make payments to UNS Energy for the use of the facility. The third party has until April 2016 to exercise its purchase option and, as a result, the associated assets have been classified as held for sale on the consolidated balance sheet as at June 30, 2015.

NON-REGULATED

Fortis Generation

In July 2015 the Corporation closed the sale of its non-regulated generation assets in Ontario for gross proceeds of $16 million. As at June 30, 2015, the associated assets have been classified as held for sale on the consolidated balance sheet. For the three and six months ended June 30, 2015, earnings before taxes of less than $1 million was recognized, compared to less than $1 million for the three and six months ended June 30, 2014. The sale is not expected to have a material impact on earnings in the third quarter of 2015.

Non-Utility

In July 2015 the Corporation signed an agreement with a private investor group for the sale of the hotel assets of Fortis Properties for $365 million. The hotel transaction is subject to typical closing conditions and is expected to be completed in the fall of 2015. As at June 30, 2015, the associated assets have been classified as held for sale on the consolidated balance sheet. In the second quarter of 2015, a $13 million impairment loss associated with these hotel assets was recognized, reflecting a reduction in the carrying value of the assets to the estimated fair value based on the expected selling price, as well as estimated costs to sell. An additional $5 million in expenses associated with the pending sale of the hotel assets were recognized in the second quarter (Note 12).

For the three and six months ended June 30, 2015, earnings before taxes related to the hotels of approximately $5 million and $1 million, respectively, were recognized compared to $6 million and $2 million for the three and six months ended June 30, 2014, respectively, excluding the impairment loss on the assets held for sale and expenses associated with the pending sale.

7. DISPOSITIONS AND DISCONTINUED OPERATIONS

Sale of Commercial Real Estate Assets

In June 2015 the Corporation completed the sale of the commercial real estate assets of Fortis Properties for gross proceeds of $430 million. As a result of the sale, the Corporation recognized a gain on sale of $129 million ($109 million after tax), net of expenses for the three and six months ended June 30, 2015 (Note 12). For the three and six months ended June 30, 2015, earnings before taxes related to the commercial real estate of approximately $5 million and $8 million, respectively, were recognized compared to $5 million and $9 million for the three and six months ended June 30, 2014, respectively, excluding the gain on sale.

As part of the transaction, Fortis subscribed to $35 million in trust units of Slate Office REIT in conjunction with the REIT's public offering. The investment in trust units is recorded as an available-for-sale asset and recognized in long-term other assets on the Corporation's consolidated balance sheet (Notes 2 and 17).

Sale of Non-Regulated Generation Assets in New York

In June 2015 the Corporation sold its non-regulated generation assets in Upstate New York for gross proceeds of approximately $77 million (US$63 million). As a result of the sale, the Corporation recognized a gain on sale of $51 million (US$41 million) ($27 million (US$22 million) after tax), net of expenses and foreign exchange impacts, for the three and six months ended June 30, 2015 (Note 12). For the three and six months ended June 30, 2015, earnings before taxes of less than $1 million were recognized compared to $1 million and $2 million for the three and six months ended June 30, 2014, respectively, excluding the gain on sale.

Sale of Griffith

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. As a result of the disposal, earnings from discontinued operations of $8 million ($5 million after tax) were recognized in the first quarter of 2014.

8. COMMON SHARES

Common shares issued during the period were as follows:
Quarter EndedYear-to-Date
June 30, 2015June 30, 2015
Number of Number of
SharesAmountSharesAmount
(in thousands)($ millions)(in thousands)($ millions)
Balance, beginning of period277,4795,719275,9975,667
Dividend Reinvestment Plan1,054391,95073
Consumer Share Purchase Plan61131
Employee Share Purchase Plan6922098
Stock Option Plans13144213
Conversion of convertible debentures (Note 13)1-11-
Balance, end of period278,6225,762278,6225,762

9. PREFERENCE SHARES

On each conversion date of the Cumulative Redeemable First Preference Shares, Series H ("First Preference Shares, Series H"), the holders of First Preference Shares, Series H have the option to convert any or all of their First Preference Shares, Series H, into an equal number of Cumulative Redeemable Floating Rate First Preference Shares, Series I ("First Preference Shares, Series I"). On June 1, 2015, 2,975,154 of the 10,000,000 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I. As a result of the conversion, Fortis has issued and outstanding 7,024,846 First Preference Shares, Series H and 2,975,154 First Preference Shares, Series I.

The holders for First Preference Shares, Series I are entitled to receive floating rate cumulative cash dividends, as and when declared by the Board of Directors of the Corporation, for the five-year period beginning after June 1, 2015. The floating quarterly dividend rate beginning June 1, 2015 to but excluding September 1, 2015 is 2.10% and will be reset every quarter based on the applicable 3-month Government of Canada Treasury Bill rate plus 1.45%. The annual fixed dividend per share for the First Preference Shares, Series H was reset from $1.0625 to $0.6250 for the five-year period from and including June 1, 2015 to but excluding June 1, 2020.

10. 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.

In April 2015, 5,730 DSUs were granted to the Corporation's Board of Directors, representing the second quarter equity component of the Directors' annual compensation and, where opted, their second quarter component of annual retainers in lieu of cash.

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 and market 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.

Year-to-date 2015, a total of 329,172 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 and six months ended June 30, 2015, stock-based compensation expense of approximately $4 million and $8 million, respectively, was recognized ($3 million and $5 million for the three and six months ended June 30, 2014, respectively).

11. 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 June 30
Defined Benefit
Pension Plans OPEB Plans
($ millions)2015 2014 2015 2014
Components of net benefit cost:
Service costs17 9 5 2
Interest costs27 20 5 6
Expected return on plan assets(35)(24)(2)(2)
Amortization of actuarial losses14 8 1 -
Amortization of past service costs (credits)1 - (3)(3)
Regulatory adjustments(1)3 1 1
Net benefit cost23 16 7 4
Year-to-Date June 30
Defined Benefit
Pension Plans OPEB Plans
($ millions)2015 2014 2015 2014
Components of net benefit cost:
Service costs34 19 9 5
Interest costs54 41 11 10
Expected return on plan assets(69)(48)(5)(4)
Amortization of actuarial losses28 15 2 2
Amortization of past service costs (credits)1 - (6)(5)
Regulatory adjustments(1)5 3 3
Net benefit cost47 32 14 11

For the three and six months ended June 30, 2015, the Corporation expensed $6 million and $14 million, respectively ($5 million and $10 million for the three and six months ended June 30, 2014), related to defined contribution pension plans.

12. OTHER INCOME (EXPENSES), NET

Quarter Ended Year-to-Date
June 30 June 30
($ millions)2015 2014 2015 2014
Equity component of allowance for funds used during construction ("AFUDC")5 1 9 3
Gain on sale of commercial real estate assets (Note 7) (1)129 - 129 -
Impairment of hotel assets held for sale (Note 6) (2)(18)- (18)-
Gain on sale of non-regulated generation assets (Note 7) (3)51 - 51 -
Net foreign exchange (loss) gain(1)(4)8 -
Interest income1 3 4 7
Acquisition-related expenses- (2)- (4)
Other(1)1 - -
166 (1)183 6
(1)Net of $17 million of expenses associated with the sale
(2)Includes a $13 million impairment and $5 million of expenses associated with the pending sale
(3)Net of $6 million of expenses and foreign exchange impacts associated with the sale

The net foreign exchange impacts relate 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 18 and 20).

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

13. FINANCE CHARGES

Quarter Ended Year-to-Date
June 30 June 30
($ millions)2015 2014 2015 2014
Interest:
Long-term debt and capital lease and finance obligations143 109 283 220
Convertible debentures- 18 - 34
Short-term borrowings2 3 5 5
Debt component of AFUDC(4)(6)(13)(12)
141 124 275 247

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.

14. 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 Year-to-Date
June 30 June 30
($ millions, except as noted)2015 2014 2015 2014
Combined Canadian federal and provincial statutory income tax rate29.0%29.0%29.0%29.0%
Statutory income tax rate applied to earnings before income taxes103 21 183 77
Difference between Canadian statutory income tax rate and rates applicable to foreign subsidiaries(3)(3)(1)(5)
Difference in Canadian provincial statutory income tax rates applicable to subsidiaries in different Canadian jurisdictions(3)(2)(8)(7)
Items capitalized for accounting purposes but expensed for income tax purposes(11)(9)(30)(22)
Difference between gain on sale of assets for accounting and amounts calculated for tax purposes(13)- (13)-
Other3 2 2 5
Income tax expense76 9 133 48
Effective income tax rate21.5%12.5%21.1%18.1%

15. 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 June 30, 2015
Weighted
Net Earnings to Common Shareholders Average EPS
Continuing Discontinued Number of
Operations OperationsTotal Shares ContinuingDiscontinued
($ millions) ($ millions)($ millions) (millions) OperationsOperationsTotal
Basic EPS244 -244 277.9 $0.88$-$0.88
Effect of potential dilutive securities:
Stock Options- -- 0.9
Preference Shares3 -3 5.4
Diluted EPS247 -247 284.2 $0.87$-$0.87
Quarter Ended June 30, 2014
Weighted
Net Earnings to Common Shareholders Average EPS
Continuing Discontinued Number of
Operations OperationsTotal Shares ContinuingDiscontinued
($ millions) ($ millions)($ millions) (millions) OperationsOperationsTotal
Basic EPS47 -47 214.8 $0.22$-$0.22
Effect of potential dilutive securities:
Stock Options- -- 0.5
Preference Shares3 -3 6.9
50 -50 222.2
Deduct anti-dilutive impacts:
Preference Shares(3)-(3)(6.9)
Diluted EPS47 -47 215.3 $0.22$-$0.22
Year-to-Date June 30, 2015
Weighted
Net Earnings to Common Shareholders Average EPS
Continuing Discontinued Number of
Operations OperationsTotal Shares ContinuingDiscontinued
($ millions) ($ millions)($ millions) (millions) OperationsOperationsTotal
Basic EPS442 -442 277.3 $1.59$-$1.59
Effect of potential dilutive securities:
Stock Options- -- 0.9
Preference Shares5 -5 5.4
Diluted EPS447 -447 283.6 $1.58$-$1.58
Year-to-Date June 30, 2014
Weighted
Net Earnings to Common Shareholders Average EPS
Continuing Discontinued Number of
Operations OperationsTotal Shares ContinuingDiscontinued
($ millions) ($ millions)($ millions) (millions) OperationsOperationsTotal
Basic EPS185 5190 214.2 $0.87$0.02$0.89
Effect of potential dilutive securities:
Stock Options- -- 0.5
Preference Shares5 -5 6.9
Diluted EPS190 5195 221.6 $0.86$0.02$0.88

16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

Quarter Ended Year-to-Date
June 30 June 30
($ millions)2015 2014 2015 2014
Change in non-cash operating working capital:
Accounts receivable and other current assets117 233 93 88
Prepaid expenses12 12 10 14
Inventories(18)(54)42 16
Regulatory assets - current portion(7)29 32 (1)
Accounts payable and other current liabilities8 (87)(2)(34)
Regulatory liabilities - current portion(10)9 4 4
102 142 179 87
Non-cash investing and financing activities:
Common share dividends reinvested40 20 74 42
Additions to utility and non-utility capital assets, and intangible assets included in current liabilities184 84 184 84
Contributions in aid of construction included in current assets4 5 4 5
Exercise of stock options into common shares- 1 2 2

17. 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 valueJune 30, December 31,
($ millions)hierarchy2015 2014
Assets
Energy contracts subject to regulatory deferral (1) (2) (3)Levels 2/33 3
Energy contracts not subject to regulatory deferral (1) (2)Level 34 1
Available-for-sale investment (4) (5)Level 133 -
Other investments (4)Level 113 5
Total gross assets 53 9
Less: Counterparty netting not offset on the balance sheet (6)(3)(3)
Total net assets 50 6
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (7)Levels 1/2/379 72
Energy contracts not subject to regulatory deferral (1) (2)Level 3- 1
Energy contracts - cash flow hedges (2) (8)Level 31 1
Interest rate swaps - cash flow hedges (8)Level 25 5
Total gross liabilities 85 79
Less: Counterparty netting not offset on the balance sheet (6)(3)(3)
Total net liabilities 82 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 wholesale trading 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 wholesale trading contracts.
(3)Includes $1 million - level 2 and $2 million - level 3 (2014 - $3 million - level 3)
(4)Included in long-term other assets on the consolidated balance sheet.
(5)The cost of the available-for-sale investment was $35 million and 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 (Note 7).
(6)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.
(7)Includes $49 million - level 2 and $30 million - level 3 (2014 - $2 million - level 1, $35 million - level 2 and $35 million - level 3)
(8)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, or those that are approved for regulatory recovery. 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 June 30, 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 June 30, 2015, unrealized losses of $76 million (December 31, 2014 - $69 million) were recognized in current regulatory assets and no unrealized gains were recognized in regulatory liabilities (Note 5).

Energy Contracts Not Subject to Regulatory Deferral

In June 2015 UNS Energy entered into long-term wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recorded in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with the ratepayer through UNS Energy's rate stabilization accounts.

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 $2 million.

Central Hudson holds interest rate cap contracts expiring in 2016 and 2017 on bonds with a total principal amount of US$64 million. Variations in the interest costs of the bonds, including any gains or losses associated with the interest rate cap contracts, are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulator and do not impact earnings.

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 June 30, 2015, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

MaturityContracts There-
Volume(year)(#)20152016201720182019after
Energy contracts subject to regulatory deferral:
Electricity swap contracts (gigawatt hours ("GWh"))20179686659219---
Electricity power purchase contracts (GWh)201735880780145---
Gas swap and option contracts (petajoules ("PJ"))201719426287---
Gas purchase contract premiums (PJ)202451513418181880
Energy contracts not subject to regulatory deferral:
Long-term wholesale trading contracts (GWh)201661,3251,310----
Energy contracts - cash flow hedges (GWh)2015144-----

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)June 30, 2015 December 31, 2014
Carrying Estimated Carrying Estimated
($ millions)Value Fair Value Value Fair Value
Long-term other asset - Belize Electricity (1)124 n/a (2)116 n/a (2)
Long-term debt, including current portion (3)(11,517)(13,027) (10,501)(12,237)
Waneta Expansion Limited Partnership ("Waneta Partnership") promissory note (4)(54)(57) (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 18 and 20).
(3)The Corporation's $200 million unsecured debentures due 2039 and consolidated borrowings under credit facilities classified as long-term debt of $1,379 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.

18. 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 June 30, 2015, FortisAlberta's gross credit risk exposure was approximately $109 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $2 mill